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C 5600.3 E38 2010 c.1
~ Iate of Oklahoma
Eleventh
Electric System Planning Report
Prepared by the Oklahoma Corporation Commission's Public Utility Division
December 2010
Oklahoma Corporation Commission
Electric System Planning Report
December 2010
Table of Contents
PAGE
EXECUTIVE SUMMARy 1
CHAPTER ONE: PREFACE AND INTRODUCTION 5
CHAPTER TWO: PROVIDER OVERVIEWS 7
CHAPTER THREE: ANNUAL ELECTRIC SERVICES SYSTEM OPERATIONS 26
TOTAL GENERATION AND POWER PURCHASES TABLE 3-1 27
TOTAL ENERGY GENERATION CAPABILITY TABLE 3-2 28
ACTUAL PEAK DEMAND DURING 2008 AND 2009 TABLE 3-3 29
ACTUAL ENERGY AVAILABLE FOR 2008 AND 2009 TABLE 3-4 30
GENERATION SYSTEM CAPABILITy 31
GENERATION SYSTEM RELIABILITY 32
GENERATION SYSTEM EFFICIENCY 33
GENERATION FUELS 35
SYSTEM FUEL USE AND COST 36
TABLE 3-5 37
ELECTRIC SYSTEM COST................................................................................................... 38
SYSTEM COSTS TABLE 3-6 38
POWER PURCHASES 39
PURCHASED POWER QUANTITY AND COST TABLE 3-7 39
FIRM CAPACITY AND RESERVES PURCHASES AND COST TABLE 3-8 40
DEMAND SIDE MANAGEMENT (DSM) PROGRAMS 40
DSM PROGRAM POTENTIAL & ACTUAL SAVINGS TABLE 3-9 41
GENERAL SYSTEM OPERATIONS BY THE PROVIDERS TABLE 3-10 42
CHAPTER FOUR: PROVIDER PROJECTIONS AND FORECASTING METHODS 43
PROJECTIONS FOR THE NEXT 10 YEARS (2010 THROUGH 2019) 44
STATEWIDE MAXIMUM ALLOWABLE DEMAND TABLE 4-1 45
REGIONAL BULK POWER TRANSMISSION FACILITIES 45
PROPOSED TRANSMISSION LINES - LINE INVESTMENTS 46
PROPOSED TRANSMISSION LINES - LINE MILES 48
PROPOSED SUBSTATIONS INVESTMENTS 49
PEAK CAPACITY FORECAST TABLE 4-2 50
FORECAST ANALySiS 51
PROVIDER FORECASTING METHODS 52
CONCLUSiON 60
GLOSSARY 61
This report was prepared in accordance with Title 17 Okla. Stat., § 157, which requires the Oklahoma
Corporation Commission to prepare a ten-year assessment of the electrical power and energy requirements
of this state and assess the need for additional or replacement generating facilities and the associated costs
of such facilities to the electric consumers of this state. The Commission shall reassess the statewide future
electrical generation requirements every two (2) years. Such assessments shall not constitute official
Commission certification or approval of any proposed generating facilities.
This publication, printed by the Oklahoma Corporation Commission is issued by the same as authorized by
Title 17 Okla. Stat., § 157. Forty copies have been prepared and distributed at a cost of $294.80. This
publication may also be found on the Oklahoma Corporation Commission's website at www.occeweb.com
under the Industry / Electric Utility tab.
ii
EXECUTIVE SUMMARY
The State of Oklahoma has seven major electric suppliers operating in the state. Of
these seven suppliers, six actually own and/or operate electric generation facilities, or
portions of generation facilities within the borders of Oklahoma. These seven electric
suppliers are collectively referred to as the Providers in this report. The Providers'
generation systems have wide variations in their power and energy production capabilities.
These Providers do not include any of the states smaller regulated or non-regulated electric
cooperatives or any of the wind energy suppliers generally located in western Oklahoma.
This report also does not include the Independent Power Producers (IPP), such as AES
Shady Point and Calpine. Nor does the report include detailed information regarding the
Southwestern Power Administration. Most of the power generated by these IPPs is
typically accounted for in the power purchase totals of the seven Providers.
Oklahoma Gas & Electric (OG&E) is the largest Provider in the state as well as the
largest investor owned (IOU) electric utility in Oklahoma, in terms of generation capacity,
energy generation capability and retail customers followed by American Electric Power
Company/Public Service Company of Oklahoma (AEP/PSO). Grand River Dam Authority
(GRDA) and Western Farmers Electric Cooperative (WFEC) are essentially identical in
terms of their generation capacity and energy generation capability. Next is KAMO and the
Oklahoma Municipal Power Authority (OMPA) who are similar in their capacity totals;
however OMPA purchases nearly one-third of its capacity while KAMO self generates
almost 90% of their required capacity, which it sells to Associated Electric Cooperative Inc.
(AECI). Only Empire District Electric (EDE), who has approximately 4,700 customers in
Oklahoma, has no generation facilities located in the state. All of Empire District's
generation facilities are located in the states of Missouri, Kansas and Arkansas. Empire
District is the smallest investor owned electric utility operating in Oklahoma; however,
Empire does have over 168,000 electric customers throughout its system. EDE is
significant in terms of its total generation with approximately 1,400 MW of total capacity.
The statewide electric capacity reserve margins for 2008 and 2009 were 14.49%,
and 18.16% above immediate need, respectively, when purchased power was included.
Based only on Provider generation capacity, the statewide reserve margin for 2008 and
1
2009 were -0.34% below need and 5.97% above need, respectively. The reserve margins
for 2008 and 2009 indicate that there existed insufficient generation capability to meet
statewide peak demand without purchasing power or implementing demand reduction
programs. See Table 3-3 for details.
If generation system efficiency is measured in terms of the kilowatt hours (kWh)
delivered to the consumer, other factors may affect the efficiency of the system as a whole.
Among these are the design and operation of the transmission system delivering power
from generation units to the distribution system, the design and operation of the physical
interconnections which tie the generation units, transmission system, and distribution
system together, and the design and operation of the distribution system which actually
delivers electrical energy to consumers.
The per megawatt hour (MWh) total delivered cost of generation and purchased
power for the individual Providers varies considerably. For 2008 the range was from
KAMO's $35.27/MWh to Empire District's $89.41/MWh. The range for 2009 was from
KAMO's $36.07/MWh to Empire's $92.93/MWh. See Table 3-6 for details.
The average cost of fuel for the Providers in 2008 was $3.62/MMBtu and
$2.57/MMBtu during 2009. The average cost of fuel per MWh generated in 2008 was
$34.99 and $24.63 in 2009. See Table 3-5 for details.
Several of the Providers purchased power from outside their generation systems.
These purchases are divided into two broad categories. The first category includes
purchases from the Southwestern Power Administration (SWPA), a federal agency that
markets power generated by hydroelectric projects, some of which are located in
Oklahoma. SWPA operates hydro facilities on several Oklahoma reservoirs and lakes
including; Lakes Broken Bow, Eufaula, Fort Gibson, Keystone, Robert S. Kerr, Tenkiller
and Webber Falls. The other category includes purchases from non-utility power
producers, both those certified by the Federal Energy Regulatory Commission (FERC) as
"Qualifying Facilities" (QF) under the federal Public Utility Regulatory Policies Act (PURPA)
and other non-utility power producers such as GRDA and AECI.
All of the Providers have supplied data on their existing and proposed transmission
facilities and substation upgrades. Many existing transmission lines will need to be
2
upgraded over the next decade. Many new transmission lines and substations will also be
needed to serve Oklahoma's growing demand for electrical energy. Transmission issues
will continue to dot the horizon like the many new wind turbines that new transmission
facilities support. There are cost recovery issues which regulators must address as well as
siting concerns on the part of landowners which could delay the full development of
western Oklahoma's extensive wind resource. Western Oklahoma's wind energy which will
not only contribute to Oklahoma's growing energy requirements, but will provide a boost to
Oklahoma's economy through wind related jobs. Other states with less renewable
opportunities will also benefit from Oklahoma's wind, assuming that transmission facilities
will be in place to support this valuable Oklahoma resource.
Over the last several years, collectively, all electricity Providers have sustained a
somewhat constant level of demand with periods of minor growth as well as periods of
minor decline in the demand for their power.
19,0000
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~
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Peak Demiand
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16,000
14,500
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1999 2000 20001 2002 2003 2004 2005 20006 2007 20DB 20D9
Note: The increase in 2008 and 2009 over 2007 is primarily due to the change in reporting of all Providers from Oklahoma only demand
to total system demand, otherwise the peak demand continues to be fairly stable.
Other than minor capacity additions related to wind generation, the only major
addition to the Providers' generation resources was the 1230 megawatt Redbud natural
gas facility near Luther, Oklahoma. In 2009 OG&E (51%), GRDA (36%) and OMPA (13%)
3
purchased the Redbud facility, which was previously owned by Kelson Energy and was
providing purchase power to Oklahoma IOUs and cooperatives. In aggregate the reserve
margin of the Providers has continued to improve over the last five years even considering
the rather significant dip in the margin in 2006.
The Providers continue to rely heavily on power purchases to meet the reserve
standards established by the Southwest Power Pool. However, almost all the Providers
operate or have plans to operate some type of demand-side management (DSM) or
demand-response programs.
4
CHAPTER ONE
PREFACE AND INTRODUCTION
This is the eleventh edition of the Electric System Planning Report (Report) prepared
by the Oklahoma Corporation Commission's Public Utility Division Staff (Staff). The current
report is the accumulation and assimilation of extensive statistical data submitted to the
Commission Staff by the major electric Providers in Oklahoma. Data gathered for this
presentation is based on the years ending December 2008 and 2009, and projections from
this data look to the next 10 years. Many resources were utilized to procure this
information including, but not limited to the following: Provider and various other websites,
brochures, and annual reports, along with company, state and federal jurisdictional filings,
and responses to information requests provided by the Providers as well as follow-up
discussions with industry personnel.
The report was prepared in accordance with 17 Okla. Stat., § 157, which requires
the Oklahoma Corporation Commission to prepare and publish an assessment of electrical
power and energy requirements of the state and assess the need for additional or
replacement generating facilities and the associated costs of such facilities to the electric
consumers of this state.
The legislation also requires that every public utility and generation and transmission
association or cooperative corporation, the Grand River Dam Authority, the Oklahoma
Municipal Power Authority, and any municipality proposing to construct generating facilities
shall submit to the Commission, for purpose of review, a list of all proposed projects for the
construction, alteration, or modification designed to increase electrical generating capacity
of any electricity-production facility located within the state along with any supporting data
the Commission might direct.
Although this report has been prepared by members of the Commission's Public
Utility Division Staff, neither the contents of the report nor the analysis methods used to
produce it constitute official Commission policy. However, the Staff, at its discretion, may
place any element of the report (including conclusions and recommendations) before the
Commission to request endorsement or other actions within the jurisdiction of the
5
Commission.
The purpose of this report is to review and summarize the electrical power and
energy requirements which existed in the State of Oklahoma for the years 2008 and 2009.
Furthermore, the report sets forth in total for the state, projections of maximum available
capacity, firm power purchases, peak energy demand, capacity margins, newly proposed
transmission lines and substations as well as upgrades to existing transmission lines and
substations, over the next ten years, i.e., from 2010 to 2019.
6
CHAPTER TWO
PROVIDER OVERVIEWS
This chapter presents a brief overview of the major energy Providers in the state and
the service territory of each. The discussions are arranged according to the relative
number of customers and sales of the Providers. The State's two largest investor owned
electric utilities, OG&E and PSO, are discussed first, since these companies have more
customers and sell more electric power in Oklahoma than any of the other Providers.
Discussed next is Empire District Electric, who is the smallest investor owned electric utility
operating in the state followed by Grand River Dam Authority, Oklahoma Municipal Power
Authority, and Western Farmers Electric Cooperative. The discussion then concludes with
KAMO Electric Cooperative.
The Providers listed in the previous paragraph serve both over-lapping and
distinctive groups of customers in Oklahoma. Private power companies such as OG&E
and PSO generally provide service to customers in non-rural areas of the state, e.g.,
Oklahoma City, Tulsa, Lawton, Muskogee, and Enid. Rural areas of the state are typically
served by Western Farmers Electric Cooperative (and the 19 distribution cooperatives
which govern Western Farmers) and KAMO Power (and the eight seventeen cooperatives
which sit on the KAMO governing board). The Grand River Dam Authority serves both
rural and non-rural areas of the state, while the Oklahoma Municipal Power Authority
provides power to municipalities that voluntarily become members of the Authority. Empire
District Electric Company serves a relatively small group of customers in both rural and
non-rural areas in the northeastern portion of the state. Empire District Electric serves
approximately 4,700 customers in Oklahoma; however, system-wide Empire serves
approximately 168,000 electric customers in a four state area, i.e., Arkansas, Kansas,
Missouri and Oklahoma. However, most of Empire's customers and their operations are
located in the state of Missouri.
7
Historical Overview
Oklahoma Gas and Electric Company
OG&E is an investor-owned public utility engaged primarily in the generation,
transmission, and distribution of electricity to retail and wholesale customers in Oklahoma
and Arkansas. OG&E is the largest electric utility in Oklahoma. In 1928, OG&E sold its
retail gas business and has since been a provider of only retail and wholesale electricity.
The OG&E electric generation system consists of nine interconnected fossil fuel generating
stations, most with multiple units and two wind farms located in western Oklahoma.
OG&E's headquarters are located in Oklahoma City.
OG&E serves more than 779,000 retail customers in Oklahoma and western
Arkansas, and a number of wholesale customers throughout the region. OG&E, with about
6,600 MW of generation capacity, generates electricity from natural gas, western coal, and
wind. OG&E's electric transmission and distribution systems span 30,000 square miles.
Enogex, OG&E's sister company, operates a pipeline system engaged in natural gas
gathering, processing, transportation, storage and marketing. The system includes about
8,200 miles of pipe, eight processing plants, and 24 billion cubic feet of storage capacity.
OGE Energy Corporation, also with headquarters in Oklahoma City, is the parent
company of Oklahoma Gas and Electric Company and Enogex. OGE Energy and its
subsidiaries have about 3,400 employees.
Oklahoma Gas & Electric Owned Generation Sources:
Plant Name Location Megawatt Capacity
1. Enid (gas) Garfield, OK 60MW
2. Horseshoe Lake (gas) Oklahoma City, OK 974 MW
3. McClain (gas) Newcastle, OK 363 MW*
4. Muskogee (coal) Muskogee, OK 1,889 MW
5. Mustang (gas) Oklahoma City, OK 613 MW
8
Luther, OK
Seminole, OK
Red Rock, Ok
Woodward, OK
601 MW*
1,724 MW
1,138 MW
1,1 MW
120 MW
101 MW
6. Red Bud (gas)
7. Seminole (gas)
8. Sooner (coal)
9. Woodward (gas)
10. Centennial (wind)
11. Sooner Spirit (wind)
*OG&E ownership capacity
For more information about OG&E refer to:
http://www.oge.com/investorrelations/Pages/lnvestorRelations.aspx
9
American Electric Power/Public Service Company of Oklahoma
PSO can trace its roots back to 1889, when the Vinita Electric Light, Ice and Power
Company was chartered in Indian Territory to provide electric service to that community.
PSO was incorporated May 29, 1913 in Oklahoma City, by consolidating that company with
electric companies and related businesses in Tulsa, Guthrie, Coalgate, Lehigh and Atoka.
PSO's founder and first president was Frederick William "Fred" Insull, who moved
PSO's headquarters to Tulsa in 1916. Insull was the nephew of Samuel Insull, a former
secretary to Thomas Edison, who later became one of the most prominent figures in the
electric utility industry.
PSO was a member of the Central and South West Corporation (CSW), an investor
owned public utility holding company. Effective June 15, 2000, CSW merged with
American Electric Power Company (AEP), a multi-state electric utility operating in 11 states.
The former CSW properties continue to operate and are identified as AEP West.
Until 1925 PSO operated in Oklahoma as part of Middle West Utilities. PSO
became part of Central and South West Utilities in 1925; and in 1947 Central and South
West Utilities became a public utility holding company. AEP West owns three other
companies aside from PSO. These three are Southwestern Electric Power Company,
Texas Central and Texas North. Southwestern Electric Power Company is an electric utility
operating in Texas, Louisiana, and Arkansas. The other two companies, Texas Central
and Texas North, are providers of electric transmission and distribution facilities for
unregulated electric utilities in the state of Texas. PSO's operations are entirely within
the State of Oklahoma. Among the Providers covered by this report, PSO is unique
because of its ownership by AEP and its relationship to the other three companies owned
by AEP West. AEP has adopted an integrated approach to long-range resource planning.
This means that PSO and the other utilities owned by AEP do long-range resource
planning in terms of the needs of the AEP system as a whole. PSO's corporate
headquarters are located in Tulsa, while AEP's corporate headquarters are located in
Columbus, Ohio.
10
American Electric Power is one of the largest electric utilities in the United States,
delivering electricity to more than 5 million customers in 11 states. AEP ranks among the
nation's largest generators of electricity, owning nearly 38,000 MW of generating capacity
in the U.S. AEP also owns the nation's largest electricity transmission system, a nearly
39,000-mile network that includes more 765-kilovolt extra-high voltage transmission lines
than all other U.S. transmission systems combined.
With approximately 4,400 MW of capacity and nearly 1,700 employees, PSO today
serves approximately 527,000 customers in 230 cities and towns across 30,000 square
miles of eastern and southwestern Oklahoma. The company's distribution operations are
organized into three districts: Tulsa, Lawton, and McAlester. PSO is headquartered in
Tulsa, with regulatory and external affairs offices in Oklahoma City, while AEP corporate is
located in Columbus, Ohio.
PSO Owned Generation Sources:
Plant Name Location Megawatt Capacity
1. Comanche Comanche, OK 294MW
2. Northeastern (coal & gas) Rogers, OK 1,593.5 MW
3. Oklaunion (coal) Vernon, TX 107 MW *
4. Riverside (gas) Tulsa, OK 948.7 MW
5. Southwestern Caddo, OK 485MW
6. Tulsa Tulsa, OK 443.2 MW
7. Weleetka Okfuskee, OK 163 MW
* PSO's power allocation of the total plant capacity based on ownership percentage.
For more information about AEP/PSO refer to: http://www.aep.com/
11
Public Service Company of Oklahoma Service Territory
12
AEP Generation Facilities
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13
Empire District Electric Company
Founded in October 1909 as a part of Cities Services Company, Empire District
Electric Company is an investor-owned public utility operating in Arkansas, Kansas,
Missouri, and Oklahoma; however, all but one of EDE's generation facilities and most of its
electric power sales are in Missouri. EDE operates seven generation plants, none of which
are located in Oklahoma. Most of Empire's generating facilities are located in southwestern
Missouri; However, Empire does have generation facilities located at Riverton, Kansas and
Plum Point, Arkansas EDE's Oklahoma customers (4,700) account for approximately 3.5%
of the total demand on the EDE system. EDE's Oklahoma electric power sales account for
about 0.2% of the total electric demand in the state of Oklahoma. EDE headquarters are
located in Joplin, Missouri.
Empire District Electric serves approximately 168,000 electric customers in
Arkansas, Kansas, Missouri and Oklahoma. Empire's Oklahoma operation is limited to the
far northeastern counties of Craig, Delaware and Ottawa.
Empire District also provides natural gas (through its wholly owned subsidiary, The
Empire District Gas Company), and water service, with approximately 217,000 total
customers in Missouri, Kansas, Oklahoma, and Arkansas. A subsidiary of the Company
also provides fiber optic services.
Empire District Electric Owned Generation Sources:
Plant Name Location Megawatt Capacity
1. Asbury (coal) Asbury, MO 207MW
2. Riverton (coal & gas) Riverton, KS 286MW
3. latan Unit 1 & 2 (coal) 12% Weston, MO 187 MW*
4. State Line (gas) 60% Joplin, MO 300 MW*
5. State Line Unit 1 (gas) Joplin, MO 96MW
6. Empire Energy Cntr (gas) LaRussell, MO 267MW
14
7. Ozark Beach (hydro) Ozark Beach, MO 16MW
8. Plum Point (coal) 7.52% Osceola, AR 50 MW*
*EDE's ownership capacity
For more information about Empire District Electric refer to: https:/Iwww.empiredistrict.com/
Empire District Electric in Oklahoma
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THE EMPIRE DISTRICT ELECTRIC COMPANY
ELECTRIC AND GAS SERVICE TERRITORIES
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Grand River Dam Authority
The Grand River Dam Authority is an Agency of the State of Oklahoma, organized
and existing pursuant to Title 82, Oklahoma Statutes, Sections 861 et seq. , one of only two
such entities that exist in the United States, which were established by governmental
action, the other being the Tennessee Valley Authority. GRDA was created by the
Oklahoma Legislature in 1935 as a conservation and reclamation district and it owns and
15
operates electric generation, transmission, and distribution facilities mainly within the
northeastern quadrant of the state. GRDA is governed by a seven member board of
directors comprised of three members appointed by the Governor, one designated by the
President Pro Tempore of the Senate, one designated by Speaker of the House of
Representatives, one designee of the Oklahoma Association of Electric Cooperatives, and
one designee of the Municipal Electric Systems of Oklahoma. GRDA is now a major
supplier of electricity not only in Oklahoma but regionally. GRDA headquarters are located
in Vinita, Oklahoma.
GRDA Owned Generation Sources:
Plant Name Location Megawatt Capacity
1. Pensacola (hydro) Langley, OK 126 MW
2. Markham Ferry (hydro) Locust Grove, OK 117 MW
3. Salina Pump Storage (hydro) Salina, OK 260MW
4. CFP 1 (coal) Chouteau, OK 490MW
5. CFP 2 (coal) 62% Chouteau, OK 322 MW*
6. Redbud (gas) 36% Luther, OK 443 MW*
*GRDA's ownership capacity
16
Grand River Dam Authority Map of Customers and Facilities
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Pensacola Dam
Pensacola Dam was the first hydroelectric facility constructed in Oklahoma. GRDA
built the dam between December 30, 1938, and March 21, 1940, when depression-era
labor was abundant. It is located between the communities of Langley and Disney,
spanning a mile across the Grand River Valley and holding back the 43,500 acres of water
that form Grand Lake 0' the Cherokees. The six units at Pensacola Dam have a combined
generation capacity of approximately 120 MW. The dam has 21 floodgates on the main
spillway and 21 on the east spillways.
Robert 5. Kerr Dam
Sometimes referred to as the Markham Ferry Project, this is the second
hydroelectric facility constructed by GRDA. Located just north of Locust Grove, Oklahoma,
the dam forms Lake Hudson, a 12,000-acre, 200-mile shoreline lake, the second in a chain
of three lakes along the Grand River. Constructed in 1964, Kerr Dam's powerhouse houses
17
four, 28.5-megawatt generators that combine to produce 114 total megawatts of electricity.
Kerr Dam has 17 floodgates and a total discharge potential of 599,000 cubic feet of water
per second.
Salina Pumped-Storage Project
The third hydroelectric project constructed by GRDA, Salina Pumped Storage
Project (SPSP) is not located directly on the Grand River system. With all possible dam
sites along the river already utilized in the late 1960s, GRDA built Oklahoma's first pumped-storage
facility in the hills southeast of Salina, Oklahoma, along the Saline Creek arm of
Lake Hudson. Though opponents argued that such an experimental facility would 'break'
GRDA, construction of the first stage was completed in 1968. The second stage completed
in 1971. The pump storage facility consists of six units which serve to pump water up into a
storage lake during off-peak hours and then become generators when the water is released
from storage. The units 1 through 4 are rated at 43 MWeach. Units 5 and 6 are rated at
44 MW each for a plant total of 260 MW.
Coal-Fired Complex
GRDA's thermal-generation facility transformed the Authority from a small,
northeastern Oklahoma hydroelectricity producer, to a major electricity supplier for the
region. Its completion nearly tripled GRDA's total generation capabilities while nearly
tripling the number of employees as well. The facility consists of two, coal fired steam
units. Unit 1 is rated at 490 MW and the GRDA portion of the Unit 2 (rated at 520 MW) is
322 MW. GRDA shares ownership of Unit 2 with KAMO.
Redbud
In 2008, GRDA, OG&E, and OMPA purchased the 1200 MW Redbud Power Plant in
Luther, Oklahoma. This is a combined cycle natural gas power plant. The GRDA portion
of the plant is 440 MW.
18
For more information about Grand River Dam Authority refer to: https:/Iwww.grda.com/
Oklahoma Municipal Power Authority
The Oklahoma Municipal Power Authority is a joint action agency created by the
Oklahoma Legislature in 1981. It is one of approximately 70 joint action public power
agencies in the United States. OMPA is composed of 36 of the state's 63 municipally
owned electric utilities. Its member municipal power companies are located throughout the
state. OMPA combines cooperation with local control to create a public power agency that
is able to economically plan, build, and operate electric generation and transmission
facilities for the benefit of all the member municipalities. Prior to the existence of OMPA,
most municipalities in Oklahoma obtained electric power from private power companies.
OMPA is governed by an 11-member board made up of city officials who manage or
operate municipal electric systems. The primary aim of OMPA is "to provide an adequate,
reliable, and affordable supply of electricity to member cities." OMPA headquarters are
located in Edmond, Oklahoma.
OMPA Owned Generation Sources:
Plant Name Location Megawatt Capacity
1. Kaw Lake (hydro) Ponca City, OK 29MW
2. Oklaunion (coal) Vernon, TX 80 MW*
3. McClain (gas) Newcastle, OK 118 MW *
4. Red Bud (gas) Luther, OK 158 MW *
5. Henry W. Pirkey (coal) East TX 15 MW*
6. Dolet Hills (coal) DeSoto, LA 25 MW*
7. Ponca City (gas) Ponca City, OK 104MW
19
*OMPA ownership capacity.
For more information about Oklahoma Municipal Power Authority refer to:
https://www.ompa.com/
Western Farmers Electric Cooperative
Western Farmers Electric Cooperative is a consumer-owned, regional electric
generation and transmission cooperative founded 68 years ago in 1941. WFEC generates
electric power from self-owned generation facilities and transmits that power to 19
distribution electric cooperatives whose service areas cover three-quarters of the state.
Western Farmer's member cooperatives operate in all but the northeastern portion of the
state of Oklahoma and serve over two-thirds of rural Oklahoma. WFEC's headquarters are
located in Anadarko, Oklahoma.
With three generating plants located at Mooreland, Anadarko and Hugo, WFEC has
total power capacity of more than 1,430 MW when the purchased hydropower is included.
Hugo Plant
The Hugo Plant is a 450 MW coal-fired generating facility located near Fort Towson,
OK. The Hugo Plant began commercial operations April 1, 1982. Water for the plant is
taken from the Kiamichi River, downstream from the Hugo Reservoir, and is pumped to an
80-acre holding pond on the plant site. The water is cleaned in a water treatment plant
before it is used in the boiler and cooling towers. The water treatment plant is large enough
to supply the needs of a city with a population of 50,000 people. The Hugo Plant can use
up to 11,000,000 gallons of water per day and when operating at peak capacity, the plant
can burn approximately 275 tons of coal per hour. Like most other Oklahoma coal-fired
plants that need is primarily supplied by the deposits of low-sulphur coal in the Powder
River Basin area near Gillette, Wyoming.
20
Mooreland Plant
The first unit at the Mooreland Plan began operating on March 27, 1964; a second
unit came on line on May 13, 1968: and the third unit first delivered power April 29, 1975.
All three units at the Mooreland Plant are conventional natural gas-fired boilers and
steam turbine design and they have a combined output of 304 MW. The Mooreland Plant,
like the Anadarko Plant, is supplied with gas by WFEC's natural gas pipeline. At peak
capacity, the three units would burn approximately 2,500,000 cubic feet of gas per hour.
Anadarko Plant
The Anadarko Plant first generated electricity in 1953. The original generator, with a
capacity of 15 MW, is still in operating condition on a standby status. A second and third
unit added later brought the capacity of the plant up to 74 MW.
The original plant uses a conventional gas-fired boiler and steam turbine method of
power generation. The three units, two Elliots and one Allis Chalmers, have provided many
thousands of hours of service and were the best available designs of their day.
In 1977 a new type of unit began operating at the Anadarko Plant called a
"Combined Cycle Unit"; the new design operates much like a turbofan jet engine on an
airplane. These new units attracted visitors from around the world who come to see first
hand the efficiency of the units. The new units added 300 MW of generating capacity. This
technology is now widely deployed in many gas-fired generation plants.
The Combined Cycle units are so named because they combine gas turbine and
steam turbine power to turn the generator. First, natural gas is burned as fuel and the hot;
expanding exhaust is directed over the turbine blades causing them to turn like a jet
engine. The exhaust is then channeled into a small boiler where the heat creates steam
that is piped into a steam turbine connected to the same generator as the gas turbine. This
process gets the maximum amount of work out of the fuel by using as much of the fuel's
energy as possible. Each of the three Combined Cycle units is rated at 100 MW.
21
Fuel for the plant is delivered by WFEC's 357 miles of 16 and 8-inch diameter
natural gas pipeline system which connects the plant to the rich gas fields in western
Oklahoma. If operating at peak capacity, the total Anadarko Plant could burn 80,040,000
cubic feet of natural gas in a 24-hour period.
WFEC Members' Service Area
• WFEC F••,Ul£lcs
• (oopcrat[vc He.ldqINrtCfj
••••••TctrU4)fi;)l b<f,lind~rieJ
.• ffLtl!ftliange CllIll!!!I
~ A'IM AIr fOr4i'. Buo
For more information about WFEC refer to : https:llwww.wfec.com/
22
KAMa Power
KAMO Electric Cooperative is a consumer-owned generation and transmission rural
electric cooperative serving customers in northeastern Oklahoma and southwestern
Missouri. In terms of generation sources, KAMO's Oklahoma and Missouri operations are
largely independent of one another. This report includes both the Missouri and Oklahoma
operations of KAMO. KAMO operates no generation facilities in Oklahoma; however,
KAMO does own 38% of GRDA's coal-fired GRDA generation unit No.2. All of KAMO's
power requirements are purchased from Associated Electric Cooperative Inc. (AECI).
KAMO's headquarters are located in Vinita, Oklahoma.
KAMO is a part of AECI which primarily serves rural Missouri; however they also
serve portions of southern Iowa and the far northeastern portion of Oklahoma. KAMO
accounts for approximately one-third AECl's operation of which approximately half is
located in Oklahoma and the other half is located in southwestern Missouri. KAMO serves
seventeen electric distribution cooperatives, eight of which are located in Oklahoma.
KAMO's partial ownership of the Grand River Dam Authority coal fired unit #2
accounts for approximately 38% of the unit or 198 MW of this facility's output. This unit has
a nameplate capacity of 520 MW. Even though KAMO owns this capacity, the power from
the GRDA facility has been integrated into AECI generation resources.
Chouteau Generation Facility
Recognized nationally for its low emissions and efficient performance, AECl's
Chouteau Power Plant is a combined-cycle, natural gas plant with the capacity to provide
520 megawatts of energy to member systems.
In operation since July 2000, the power plant is located in northeastern Oklahoma
on 22 acres inside an industrial park. Natural gas is supplied to the plant from a connection
on a high-pressure mainline running through plant property. A 161-kV substation connects
and transmits power generated by the plant to the integrated transmission system of KAMO
Power, one of AECl's six member-owners.
23
Under AECl's direction, Siemens designed and built the plant and provides daily
operation and maintenance of the unit. Because the plant is highly automated, only about
20 skilled employees are needed to operate and maintain it.
The Chouteau Power Plant has greater efficiency than a simple-cycle combustion
turbine unit because it employs both a steam turbine and a combustion turbine to power the
generator.
Chouteau features two heat-recovery steam generators (HRSGs), each measuring
about 70 feet by 100 feet that capture exhaust heat to power a steam turbine. In contrast,
hot exhaust from the gas turbine is vented to the atmosphere on a simple-cycle plant.
At Chouteau, exhaust heat enters the HRSG, or boiler, at about 1,085 degrees
Fahrenheit and moves through the structure, heating tubes of water to create steam to
power the steam turbine, which turns the generator to produce electricity. Afterward, the
exhaust is vented from the stack at about 200 degrees.
This heat-recovery system increases the efficiency of the unit to 58 percent,
compared with 33 percent efficiency of a simple-cycle plant.
Operating at full load, the plant burns roughly 86 million cubic feet of natural gas per
day. Environmental impact of operating the unit is minimal. Its emissions are among the
lowest in the state.
For more information about KAMO refer to: http://www.kamopower.com/
24
Associated Electric Cooperative Inc. and Affiliated Cooperatives Service Areas
• Oklahoma
Conception
WiJ\dfarm
Cow Brancll
'WInd Farm
BIUlltr.lU Ridge
Wind Farm
ThDmM Hill
Enilf1YCenter
DellPow~r Plant .•
Dell.Arkansas
25
CHAPTER THREE
ANNUAL ELECTRIC SERVICES SYSTEM OPERATIONS
INFORMATION
This chapter provides an overview of some of the fundamental parameters related to
the generation and purchase of electrical power by the Providers during the years 2008 and
2009.
Total Existing Generation Capacity and Power Purchases
The Tables in this section of the Report present data related to generation capacity,
peak demand, energy generation, and energy sales for each Provider's system. The data
is presented on a total system basis for Providers that operate systems extending beyond
the State of Oklahoma.
The data presented in these Tables is the most current and accurate available and
was supplied by the Providers specifically for the Electric System Planning Report. Every
effort has been made to ensure that the data supplied was proper and valid.
Some Providers used curtailments in their operating systems. Curtailments are
generally called for when operating reserves fall below a certain megawatt level. This level
or margin expresses the required resources that must be available to the utility to meet
system emergencies. The state's two largest IOU's, OG&E and AEP/PSO, have
curtailment tariffs. Under these tariffs the utility can curtail a customer's usage when
necessary during certain peak demand periods. These programs are voluntary, and the
customers are compensated with discounted rates. In order to preserve the required power
reserve margin, the utility may curtail at times when the demand on its system approaches
maximum system capability.
26
Total Generation and Power Purchases
Table 3-1
Existing Power Generation Capacity and Purchases by Providers (megawatts)
A B C D E F G H I J K L M II 0 P Q R
Total Total Power
lIaturai Provider lion-Utility Capacity
Coal Gas Hydro Oil Power I!atura! Gas Renewables (COGEI!) (Generation
Power Power Power Power Renewables Generation Coal Power Power HydroPower Oil Power Power SWPAPower other Power Power Total Power and
Provider Year Gen. Gen. Gen. Gen. Power Gen. capacity Purchases Purchases Purchases Purchases Purchases Purchases Purchases Purchases Purchases Purchases)
(1+J+K+l+M+ff+
(C+I>tBf+G) O+PI (I!+Q)
2008 1,031 3,349 0 25 0 4,405 0 254 0 0 27 44 0 0 325 4,730
AEPIPSO
2009 1,026 3,359 0 25 0 4,410 0 390 0 0 17 44 0 0 451 4,861
2008 380 854 16 0 0 1,250 162 0 0 0 7 0 0 0 169 1,419
Empire
2009 382 859 16 0 0 1,257 162 0 0 0 7 0 0 0 169 1,426
2008 812 0 500 0 0 1,312 0 228 0 0 0 13 0 0 241 1,553
GRDA
2009 812 430 503 0 0 1,745 0 78 0 0 0 13 0 0 91 1,836
2008 198 0 0 0 0 198 889 805 181 14 0 0 0 0 1,889 2,087
KAMO
2009 198 0 0 0 0 198 781 707 159 12 0 0 0 0 1,659 1,857
200B 2,595 3,517 0 0 4 6,116 0 0 0 0 50 0 0 490 490 6.606
OG&E
2009 2,542 4,058 0 0 4 6,604 0 0 0 0 50 0 0 490 490 7,094
2008 147 293 29 0 8 477 0 () 0 0 () () 259 0 259 736
OMPA
2009 147 439 29 0 8 623 0 0 0 0 0 0 193 0 193 816
2008 440 765 0 0 0 1,205 0 0 0 0 0 279 0 0 279 1,484
WFEC
2009 440 900 0 0 0 1,340 0 0 0 0 0 279 0 0 279 1,619
2008 5,603 8,778 545 25 12 14.963 1,051 1,287 181 14 84 336 259 490 3.638 18,601
Total
2009 5,547 10,045 548 25 12 16,177 943 1,175 159 12 74 336 193 490 3.320 19,497
Percent of 2008 30.12% 47.19% 2.93% 0.13% 0.06% 80.44% 5.65% 6.92~t 0.97% 0.08% 0.45% 1.81% 1.39% 2.63% 19.56% 100.00%
Total
Energy 2009 28.45% 51.52% 2.81% 0.13% 0.06% 82.97% 4.84~. 6.03'_ 0.82% O.OfW. 0.38% 1.72% 0.99~. 2.51% 17.03% 100.00%
Note: Based upon discussions with OG&E and OMPA. Staff believes that the companies used different SPP formulas (timing) to determine the available capacity for Renewable Power Gen.
(column "GOO). Staff believes that the total for both companies should be reported as 6 megawatts for both 2008 and 2009.
27
Total Energy Generation Capability
Table 3-2 Report
Existing Maximum Energy Generation Capability of Providers (megawatt hours)
A B C D E F G H
Total Provider
Ener'gy
Generation
Provider Year Coal tlatural 'Gas Hydro Oil R,enewables Capacity
(C+D+E+F+G)
2008 9,031,560 29,337,240 I) 219,000 o 38,587,800
,A,EPJPSO
2009 8,987,760 29,,4.24,B40 0 219,000 0 38,631,600
20008 3,328,800 7,481,040 140,160 ° 0 10,950,000
Empire
2009 3,346,320 7,524,840 140,160 0 0 11,011,320
20018 7,1~13,1120 9'70,1070 4,380,00:0 0 0 12.463,290
GRDA
2009 7.113,1i20 3,880,680 4,406,280 0 0 15,400,080
2008 1,734,000 0 0 0 0 1,734,000
KAMO
2009 1,734,000 0 0 0 0 1,734,000
2008 22,732,200 30,808,920 0 0 35,040 53,576.160
OG&E
2009 22,267,920 35,548,080 0 0 35,040 57,851,040
2008 1,291,000 2,574,000 255,000 0 70,000 4,190,000
OMPA
2009 1,288,000 3,846,000 254,000 0 70,000 5,458,000
2008 3,276,000 5,361,,000 0 0 0 8,637,000
WFEC
2009 3,276,000 6,307,000 0 I) 0 9,583,000
20008 48,506,680 76,532,370 4,775,160 219,000 105,040 130,138,250
TOTAL
2009 48,013,120 86,531,440 4,800,440 219,000 105,040 139,669,040
Per,oe:nt of 2MB 37.,21% 58.81%. 3.61% 0.17% D.oS%. 100.00%.
Tota.l
Energy l{J(}9 34.38%. 61.95%. 3.44% O.16'-~ O.OS%. 100.00%
Note: Based upon discussions with OG&E and OMPA. Staff believes that the companies used different SPP formulas (timing) to
determine the available capacity for Renewables (column "G"), Staff believes that the total for both companies should be reported
as approximately 52,000 megawatt hours for both 2008 and 2009.
28
Table 3-3, Report
Actual Peak Demand for the Providers (megawatts)
A B C D E F G Hi I J K L fill ~I 0
Total P,Qwer
Capacity Reserve
Peak System Actual Peak Adjusted ~GeneratiQn Res,elve Margin
Natural. Hydro Purchase P.eak Demand Side Peak and Reserve Mar'g,inWith llirithout
Prov.ider Year C.oalPeak Gas,P,eak Peak Oi\!Peak Renewables Power Demand Management Demand Purcilas'es) Margin Purchases Purchases
~q+ID~+IE)+ (I)+(J) ILHK) IM)!(K) UMHHW(K) (f)+(G)
20>0'8 499 2,487 0 () ao U34 4,201) 7 4,207 4,686 479 111.39% -15.57'%
AEPJPSO
20109 907 2,0117 0 0 73 9197 3,994 5 3,999 4,817 B118 20.46% -4.48%
2008 344 642 14 0 6 146 1,152 8 1,160 1,426 266 22.91% 10.33%
Empire
2009 344 575 14 0 6 146 1,085 8 1,093 1,426 333 30.44% 17.09%
2008 71iO 0 317 0 0 1150 1,171 10 1.1,87 11,553 366 30.8:3% 18..20%
GRDA
2009 7.25 400 274 I} I) 0 1,,3919 10 11,409 1,758 349 24..77% 24.77%
2008 198 0 .0 o 0 1672 1,,870 .0 1,870 2,087 217 11.60% 11.60%
KAMO 20,09 198 0 0 ° 0 1445 1,643 00 1,643 1.857 214 13.0,2% 13.02%
2008 2,358 2,772 0 I} 54 383 5,567 0 5,567 6,485 9118 16.49% 9.61%
OG&E
2009 2,378 3,122 0 0 115 443 5,958 0 5,958 6,876 918 15.41% 7.97%
2008 125 212 5 n 0 316 668 0 658 736 78 11.8,5% -36.17%
OMPA
2009 108 340 30 0 2 1917 671 0 677 816 139 20.53% -8.57%
2008 429 4910 256 0 44 257 1,476 0 1,476 1,484 8 0.54% -16.87%
WFEC
2009 402 6,04 219 0 25 1194 1,444 0 1.444 1.619 175 12.12% -1.32%
2008 5,429 7,.408 679 14 184 2,386 16,100 25 16,125 18,457 2,332 14.46% -0.34%
Total
2009 5,711 7,765 613 13 121 1,,977 16,200 23 16,223 19,169 2,946 18.16% 5.97%
29
Table 3-4
Actual Energy Available from the Providers tmegawatt hours)
-
A B C D E F G H I
Annual Annual
Purchased Provider
Provider Y,ear Coo'li Natural Gas Hydro Oil Renewabres Energy Energy
IC+I)fE+
F+G+H)
.2008 6,998,000 73760:00 0 0 1,322,000 5,035,000 21,231,000
AEPiPSO ' ,
2009 1,224,000 6,144,000 0 0 1,4.20,000 5,083,000 .20,411,000
200B 2,116,314 1,11.9,,814 32,601 339 593,544 1,631,041 5,493,553
Empire
2009 2,126,,950 143,,831 16,133 139 79'0;035 1,:525,518 5,263,206
.2008 5,612,618: 239,013 1,421,325 I) 0 343,244 1,622,260
GRDA
2009 5,493,609 1,3.22,444 1,283,516 0 I) 128,920 8,223,549
2008 14211249 0 '0 0 0 8663383 10,084,632
KAMO ' , , ,
2009 1I,346,R26 (} '0 0 '0 1,260,568 8,601,394
2008 11,511,480 1,621,618 I) 0 604,880 2,618,530 28,482,508
OG&E
2009 15,063,228 9,431,266 ° I) 548,195 2,313,8,30 21,356,519
.2008 953;000 608000 184,000 '0 112;000 881,000 2,198~000
OMPA
,
.2009 692,:000 11,.51000 150,000 '0 153;000 196,000 2,942,000 I: t
2008 3,161,660 1,482,914 1,045,000 I) 1,665,689 215,000 1,636,263
WFEC
2009 3101588 1,501,654 905,934 0 1,468,635 530,683 1,514,494 Jl' , ,
2008 31840321 1:B,953,419 .2,68B,9.26 339 4,;358,11'3 19,501,198 83,348,316
TOTAL ' ,
2009 35,'048,2011 20,.900"t95 2,41,6,243 139 4,319,865 111,638,519 17,441',162
30
Generation System Capability
The generation capability of an electrical generation system is defined as the total
net megawatt generation capacity of the units operating on the system. The watt is the unit
of measurement used to quantify the power generating capacity of electrical generators. A
kilowatt (kW) is 1,000 watts, while a megawatt (MW) is one million (1,000,000) watts. This
means that the measurement of the kilowatts or megawatts available from an electrical
generation system tells us how much power is available from that system. Typically,
electrical generation systems are designed so that the power output of the system meets,
or exceeds, the maximum demand for power expected to be placed on the system.
Electric bills to customers can be based on either kilowatts or kilowatt hours (kWh)
or both. Most bills to residential and commercial customers have charges computed in
terms of kilowatt hour usage, while bills to some larger commercial customers and most
industrial customers have charges computed in terms of both kilowatt hours and kilowatts.
The kilowatt hour portion of an electrical bill usually is referred to as billing for "energy
usage," while the kilowatt portion of such a bill usually is referred to as billing for "demand
on the generation system." The energy charge is based on the total kilowatt-hours used.
Kilowatt-hours are the unit of electricity measured by the electric meter. For example, a 100
watt light bulb burning for 10 hours would be 1,000 watt-hours or 1 kWh (100 watts X 10
hours = 1000 watt-hours).
This billing division has been described in terms of a commodity charge (kilowatt
hours) for energy used, and a capacity reservation charge (kilowatts) for construction and
ownership of the generation units themselves, as well as transmission and distribution
facilities. However, this portrayal of the billing division is incorrect in one very important
respect. In fact, the bills of all customers include payment to cover both the cost to build
and own the generation, transmission, and distribution systems, as well as the costs
associated with actually using those systems to generate electricity. The bills of some
commercial customers and most industrial customers show this division explicitly, while the
two types of cost are aggregated in bills delivered to residential customers and most
commercial customers.
31
There is wide variation in the power and energy production capability of the
Providers' generation systems. OG&E is the largest Provider in the state in terms of
generation capacity and energy generation capability, followed by AEP/PSO. GRDA and
WFEC essentially are identical in terms of their generation capacity and energy generation
capability, with OMPA coming fifth in these categories. Empire District neither owns nor
operates a generation plant within Oklahoma. Empire District's generation facilities are
located in the states of Missouri, Kansas and Arkansas. Empire District is the smallest
investor owned electric utility operating in Oklahoma with approximately 4,700 customers
located in northeastern Oklahoma. KAMO owns approximately 38% of GRDA's No.2 coal-fired
generation facility located in Chouteau, OK. Associated Electric Cooperative, Inc. has
integrated KAMO's portion of this unit into its generation resources. AECI provides
approximately 99% of KAMO's power needs. The remainder of the power is purchased
from small suppliers.
Generation System Reliability
The reliability of a generation system is an expression of the capability of the system
to successfully meet the maximum demand likely to be placed on the system during some
specified time interval. The expected reliability of a system of generation units can be
measured in one of several ways. First, one can compute the actual and forecasted
reserve and capacity margins for the system. Both reserve margin and capacity margin are
ratios. The reserve margin for a generation system is the difference between peak system
generation capacity and actual peak demand on the system during a year divided by the
actual peak demand on the system, expressed as a percent. Capacity margin is this same
difference divided by the peak system generation capacity of the system. These
computations can be made using either actual or forecasted values for peak system
generation capacity and peak system demand.
Loss of load probability (LOLP) is another way to measure the expected reliability of
a generation system. LOLP is computed based on forecasts of peak generation system
capacity and peak system demand. LOLP is the computed probability that the system will
32
be unable to serve the maximum (peak) demand placed on it over some specified planning
horizon. LOLP is expressed in terms of the number of days during the planning horizon
when the system will be unable to meet the peak demand placed on it. A well-designed
and managed generation system is likely to have a LOLP of one day in 10 years. This
formula says the system is expected to be unable to meet the maximum demand placed on
it only one day every 10 years. Many power production planning computer models
compute a reliability measure very similar to the LOLP. These models compute the
expected loss of load hours during each year of the planning horizon.
In terms of the reliability criteria described above, not all of the Provider's generation
systems are "reliable" on a stand-alone basis to the point that system capability has
sufficient reserve; however, when Provider generation capacity and purchased power are
combined, (See Table 3-3 Column N) the reserve margins are significantly improved. For
2008, the highest reserve margin among the Providers operating generation facilities in
Oklahoma was GRDAs 30.83%, while the lowest was WFEC's 0.54%. For 2009, the range
was from Empire District's 30.44% to WFEC's 12.12%, including purchased power. The
generation systems of the other Providers fall somewhere between these extremes. For
the state as a whole, the reserve margins for 2008 and 2009 are 14.46%, and 18.16%,
respectively, when purchased power is included. When only Provider generation capacity
is considered, the range for 2008 is from GRDA's 18.20% to OMPA's negative 36.17%,
while the range for 2009 was from GRDA's 24.77% to OMPA's negative 8.57%. Based
only on Provider generation capacity, the statewide reserve margins for 2008 and 2009
were a negative 0.34%, and a positive 5.97%, respectively. The reserve margin for 2008
and 2009 indicates there was insufficient generation capability to meet statewide peak
demand without purchasing power or demand reduction programs.
Generation System Efficiency
Measurement of the efficiency of a generation system is an assessment of the
relative amount of input resources and monetary cost required by the system to generate
each unit of electrical energy (kilowatt hour) coming from the system. We shall refer to the
first type of efficiency as resource efficiency. The most widely used measure of resource
33
efficiency is the system heat rate. The system heat rate is defined as the number of British
thermal units (Btu) required by the system to generate a kilowatt hour of electrical energy
during some specified time interval. The system heat rate can be computed as an average
for the system over a period of time, such as a year, or as the incremental heat rate for the
system. The system incremental heat rate is the number of Btu required to generate the
next kilowatt hour produced by the system. A system's heat rate may be calculated by
dividing the system's Btu output by the quantity of kilowatt hours produced by the system
(Heat Rate = (Btu + kWh).
Both the system average and system incremental heat rate can be used as
measures of actual system performance over a historical period of time, for example over a
year's time. However, both system heat rates can also be forecasted by power production
planning computer models. In assessing the future efficiency of the system, the
incremental system heat rate is a more useful forecasted value. However, it also is more
difficult to forecast, since it is based not only on expected system operations but also on
past tests of the system's generation efficiency at various load levels. When interpreting
system heat rates, the system is more efficient as the heat rate drops.
The second criterion used to assess the efficiency of a generation system is the
cost per kilowatt hour produced by the system. Like the system heat rate, the cost per
kilowatt hour produced also can be computed either as an average or as the cost to
produce the next kilowatt hour from the system (incrementally). Unlike the system heat
rate, however, the cost per kilowatt hour produced is an economic rather than a physical
measurement of the system's efficiency. This difference is of little significance when the
historical average cost per kilowatt hour produced is computed, since this value is
computed using measurements of past cost and kilowatt hour generation.
This difference is more important in the case of forecasts of cost per kilowatt hour
produced, since forecasting the cost of such variables as cost of fuel, maintenance cost,
and operational cost is speculative when compared to forecasts of the heat content of fuels
or the mechanical efficiency of the generation units operating on the system.
Table 3-10 for each of the Providers contains the system average heat rate for each
Provider's generation system, for the years 2008 and 2009. For 2008, these heat rates
34
ranged from 6.549 to 10.91 Btu/kWh. KAMO's system had the highest (or least efficient)
heat rate for 2008 at 10.91, while GRDA's system had the lowest (or most efficient) heat
rate for 2008 at 6.549. KAMO's system also had the highest heat rate, at 11.07 for 2009,
while GRDA's system had the lowest heat rate, 7.027 for 2009.
Many factors can impact the efficiency of a generation system. Several of these
factors relate to the generation units in operation on the system. Among these factors are
the technology bases of the generation units, the age of the generation units, the manner in
which the units are operated, and the maintenance performed on the units. If generation
system efficiency is measured in terms of the kilowatt hours delivered to the consumer,
other factors may affect the efficiency of the system as a whole. Among these are the
design and operation of the transmission system delivering power from generation units to
the distribution system, the design and operation of the physical interconnections which tie
the generation units, transmission system, and distribution system together, and the design
and operation of the distribution system which actually delivers electrical energy to
consumers.
Generation Fuels
This discussion is limited to a review of the fuels used by the Providers' generation
systems during 2008 and 2009.
Nearly all generation units operated by the Providers are fired by fossil fuels. The
exceptions are the hydroelectric facilities operated by Empire District Electric in Missouri
and the hydroelectric operations in Oklahoma owned by GRDA and OMPA, and the wind
generation owned by OG&E in western Oklahoma. There are other non-fossil fuel
generation facilities located in the state. These facilities include the hydro plants operated
by the Southwestern Power Authority and various wind generation facilities located
predominately in the western portions of the state. These non-fossil fuel facilities generally
provide purchase power to most if not all of the Providers.
Table 3-1 indicates in 2008 and 2009 there were 5,603 and 5,547 MW, respectively,
of coal-fired generation capacity owned by the Providers who operate in the State of
35
Oklahoma. Table 3-1 shows that in 2008 there were 8,778 MW of natural gas-fired
generation capacity, which increased significantly in 2009 to 10,045 MW. Oil-fired
generation was 25 MW for both years, while hydro generation capacity for the same period
was 545 MW in 2008 and 548 MW in 2009. Renewable capacity, which was primarily wind,
was 12 MW for both years.
Table 3-4 shows the actual electrical energy available to the Providers during 2008
and 2009 by fuel type. These values represent the actual energy produced in terms of
megawatt hours, where the values in Table 3-1, discussed in the preceding paragraph
represent the capacity of the Providers generation facilities in megawatts. Coal-fired
generation was 37,840,321 MWH for 2008, and 35,048,201 MWH for 2009, while natural
gas-fired generation was 19,953,419 MWH for 2008, and 20,900,155 MWH for 2009.
Hydro generation was 2,688,926 MWH for 2008, and decreased to 2,416,243 MWH for
2009, which was still a significant increase from the previous report. Once again, GRDA's
hydro energy accounted for the majority of all hydro production. Empire District accounted
for nearly all oil generation which was 339 MWH for 2008 and, only 139 MWH in 2009.
Electric generation by renewable sources (predominately wind) for 2008 was 4,358,113
MWH, and 2009 was 4,379,865 MWH. Renewable energy generation increased
significantly for most companies over the two-year period primarily due to the abundance of
wind in Oklahoma. With the addition of needed transmission facilities, wind energy should
continue to play a significant role in Oklahoma's future energy picture. In 2010 the
Oklahoma Legislature past two bills related to wind energy, i.e., HB 3028 and HB 2973.
HB 3028 established a renewable energy standard of 15% for the state, which meant that
15% of the state's generation in 2015 would be from renewable energy sources. HB-2973
set a standard for the decommissioning of wind turbines and wind farms.
System Fuel Use and Cost
Table 3-5 below, presents information on the total fuel burned by the Providers in
2008 and 2009 to produce electrical energy. Fuel use for 2008 varies from 259,988,755
MMBtu used by OG&E to 13,884,769 MMBtu used by OMPA. For 2009, the range is from
36
247,463,096 MMBtu burned by OG&E to 13,793,236 OMPA. Fuel cost data is presented in
two forms in Table 3-5, i.e., cost per million British thermal units ($/MMBtu) and cost per
megawatt hour ($/MWh). The first is a measurement of the average cost per heat unit of
the fuel itself; while, the second is the average fuel cost related to each MWh generated.
The second is the portion of the per MWh cost of electricity generation which is attributable
to the cost of the fuel used to generate an average MWh from fossil fuel burning plants.
The average cost of fuel for the Providers listed in Table 3-5 is $3.62/MMBtu for 2008 and
$2.57/MMBtu for 2009. The average cost per Mwh generated was $34.99 in 2008 and
$24.63 in 2009.
Table 3·5
System Fuel Use and Cost for the Providers (mec awatt hours}
A B C D E F G
Average
Average
Total Annual Quantity of
Total Fuel Fuel Cost
Energy
Provider Year Generation Fuel Burned Cost ($) ($IMMBtu) Cost- Fuel
(MWH) (MMBtu) (Ell(D) ($1MWH)
(E)/tC)
.200B 14,872,057 1149,575,114 $722,639,130 $.4.83 $48.59
AEPiPSO
21)09 13,9166,152 1141.,056,236 $.370,769,277 $2.63 $26.55
.200H 3,236,467 31,770,105 $100,005,446 $.3.15 $.30.90
Empire .200.9 2,8.70,920 29,684,28.7 $.94,430,.829 $.3.18 $32.8.9
2008 7,270,874 47,613,455 $98,340,950 $2 ..07 $13 ..53
GRDA .2009 8,055,B28 56,604,665 $1130,956,467 $2.31 $1626
.2008 1,421,249 15,503,074 $22,764,000 $1.47 $.16.02
KAMO
2009 1,346,826 14,912,789' $22,920,000 $.1.54 $17.02
2008 25,6,96,fil.37 259,988,755 $865,725,.266 $3.33 $33.69
OG&E
20n9 25,008,476 247,463,096 $624,859,240 $2.53 $24.99
2008 1,561,000 13,884,769 $52,43.5,836 $.3.78 $33.59
OMPA
2009 1,844,000. 13,793,236 $42,277,148 $3.07 $.22.93
2008 4,650,000 49,810,298 $1192,452,381 $3.86 $41.39
WFEC
2009 4,608,000 49,437,611 $1'35,136,009 $.2.73 $29.33
.2008 58.,708,484 568,145,570 $2,054,363,00.9 $.3.6.2 $34.99
TOTAL
.2009 57,700,202 552,951,9'20 $1,421,348,970 $2.57 $24.63
37
Electric System Cost
Table 3-6 summarizes cost data taken from Table 3-10 presented below. The costs
in Table 3-6 are those involved with both owning and operating the Providers' generation
systems, as reported by the Providers. These costs are divided into five categories.
Columns (D) and (E) include the cost to purchase off-system power and the cost incurred
to actually operate the generation system producing electrical power. Columns (F), (G),
(H), and (I) present the costs associated with constructing and owning the electrical
generation systems. The final column of Table 3-6 presents the average cost per
megawatt hour to generate power on each Provider's system. The final row in Table 3-6 is
labeled "total." This row presents the total cost for each column, as well as the average
cost per megawatt hour for all the Providers together. The average cost of generation for
the Providers was $65.34/MWh in 2008 and $57.1 O/MWh in 2009. The megawatt hour cost
of generation for the individual Providers varies considerably. For 2008, the range was
from KAMO's $35.27/MWh to Empire District's $89.41/MWh. The range for 2009 was from
KAMO's $36.07/MWh to Empire District's $92.92/MWh.
Table 3-6
System Costs for the Providers
A B C D E f G H I J K
Fuel and Operations &
Annual MWH of Purchase Maintenance Depreciation Average Cost
Provider Year Energy Sales Power Cost Cost Cost Debt Cost Taxes Net Income Total Revenue perMWH
(D)f-(E)+(f)+(G)+(
Hlf-!I) 1000"(J)!(C)
2008 19,839,000 S1,052,519 S248,018 $1.05,249 $75,088 SO :578,484 $1,559,358 $78.60
AEP/PSO
2009 19,207,000 :5570,155 $293,595 $110,149 $57,306 $0 $75,602 $1,106,807 $57.63
2008 5,116,502 $182,518 $93,209 $50,019 $28,793 $63,189 :539,722 :5457,449 $89.41
Empire
2009 4,893,941 $170,311 $86,145 :547,746 S32,343 $76,938 :541,296 :5454,780 $92.93
2008 7,047,353 $128,680 1544,172 $32,645 $37,722 $0 $82,969 $326,188 $4629
GRDA
2009 7,728,133 $138,546 $56,467 $48,596 $52,779 $0 $20,478 $316,866 :541.00
2008 10,084,632 $184,427 $124,626 $24,829 $0 $0 $21,826 $355,708 $3527
KAMO
2009 8,607,394 $145,029 $126,596 $26,313 $0 SO $12,545 $310,483 $36.07
2008 28,162,429 $1,122,730 $423,602 $145,533 $81,589 $0 $143,007 $1,916,461 $68.05
OG&E
2009 26,880,647 $801.41'8 $442,514 $166,245 $96,106 $0 $200,440 $1,706,723 $63.49
2008 2,223,000 :596,524 $8,861 $11,544 $25,633 $0 -$231 $142,331 $64.03
OMPA
2009 2,203,000 $68,228 $11,907 S15,111 $29,075 $0 -$1,779 $122,542 $55.63
2008 7,463,000 $321,311 $69,501 $20,643 :532,994 $0 $21,111 :5465,560 $62.38
WFEC
2009 7,2.86,000 :5224,132 $73,547 $22,969 $32,617 $0 $'13,841 $367,106 $50.39
2008 79,935,916 $3,088,709 $1,011,989 $390,462 $281,819 $63,189 $386,888 $5,223,055 $65.34
TOTAL
2009 76,806,115 $2,117,819 $1,090,771 5437,129 $300,226 $76,938 $362,423 $4,385,307 $57.10
Note: For OG&E this value is funds available for payments to both preferred and common shareowners.
38
Power Purchases
Table 3-1 shows that several of the Providers purchase power from outside their
generation systems. These purchases are divided into two primary categories. The first
category includes purchases from the Southwestern Power Administration (SWPA), a
federal agency that markets power generated by federal hydroelectric projects, located in
Oklahoma (operated by the Corps of Engineers.) The second category includes purchases
from non-utility power producers, both those certified by the Federal Energy Regulatory
Commission (FERC) as "Qualifying Facilities" (QF) under PURPA and other non-utility
power producers.
Table 3-7 shows the total energy in megawatt hours that the Providers purchased
during the years 2008 and 2009. It also shows the total costs of purchasing this energy.
Table 3-1
Purch,as,ed Power Quantity and Cost fa,r the Providers
A B C D IE
Purc!has.ed
Average Purc!has,ed
Provider Year Einergy Quantity
Purclhas,ed 8nergy 18ner1gy!Cost
(M1IIl11l1~
Cost ($)
($JM1IIlH)
(D)/(C)
2008 6.357,096 $329,879.997 $51 ..89
AEPIPSO
2009 6,502,504 $199,3816,178 $30.66
200B 2,224,5B5 $B2,5112,734 $.37.09
Empire
2009 2,31.5,55.3 $7.5,880,,646 $32.77
20081 343.244 $30,339.495 $818.39
GRDA
2009 1281,920 $7,589,678 $581.87
200B B,663,.383 $161,662,911: ,$1B.6,6
KAMO
2009 7,26,O,.56B $1122,,109,,077 $16.82
20081 4,364,90.5 $257 ,00.5,065 $581.13:8
OG&E
20091 3,837,&35 $176,55&,755 $46.UO
200B 8B1,OO.3 $44,08B.164 $50.04
OMPA
2009 795,6'06 $25,950,B52 $32.62
2008 .2,9881,000 $128,8481,67.2 $43.12
WFEC
2009 2,905,[1100 $881,8:96,002 $30.60
2008 25,822,216 $1,,034,337,038 $40.06
TOTAL
2009 23,745,986 $696,371,18B $29.33
39
Table 3-8
Firm Capacity and Reserves Purchases and Cost for the Providers
A B C D E
Purchased Capacity Av,erage Capacity
ProvIder Year Res'erv,es Capaci,ty Res'erve Reserve Cost
(MW) Cost ($) I$JMW)
(D)1(C)
2008 325 $5,609,000 $17,258
AEPiPSO
2009 451 $13,401,000 $29,714
2008 162 $16,193,520 $99,,9600
Empire
2009 162 $16,193,520 $99,9&0
2008 228 $10,308,221 $45,211
GRDA 2009 78 $3,519,826 $45,126
KAMO 22000089 223355 NN//AA NN//AA
2008 740 $93,879,037 $126,864
OG&E
2009 440 $83,149,933 518'8,977
20008 103 $8,847,,000 $85,893 OMPA 2009 101 $7,50.6,000. $74,317
2008 91 $5,715,000 $62,802
WIFEC
2009 91 $4,771,000 $52,429
2(1)008 1",649 $1:40,5511,,778 $85,235 TOTAL 2009 11,323 $128,541!,279 $97,159
Most of the electricity Providers have firm contracts in place to purchase up to a
fixed amount of energy from outside parties. Table 3-8 illustrates the total capacity that
each Provider had available under contract in the years 2008 and 2009. The table also
shows the capacity reserve costs associated with these contracts.
Demand-Side Management Programs
Almost all the Providers operate or have plans to operate some type of demand-side
management (DSM) programs. Of the major Oklahoma Providers in Table 3-9, only KAMO
and OMPA currently do not operate DSM programs.
40
Table 3-9 summarizes the potential and actual savings from DSM programs
currently operating on the Providers' systems. This table divides DSM programs into two
types. The first type consists of DSM programs designed to control or manage peak
demand. The second type includes DSM programs designed to promote energy
conservation by customers on the Providers' systems. Savings from the first type of DSM
programs are measured in terms of the megawatts of capacity additions the Providers were
able to defer or cancel because of these programs and the cost associated with these
capacity additions. Savings from the second type of DSM programs are measured in
megawatt hours of energy not generated by the Providers, and the costs associated with
that generation, which are directly attributable to the operation of the energy conservation
programs.
Table 3-9 Report
DSMProgram Potential & Actual Savings (megawatts & megawatt hours) for the Providers
A B C D E f
Peak Demand Ener'9Y Actual Peak
Actual Ener'9Y
Provider Year Management Conservati on Dem.and
Potentiaj 'MWH) Potential IMWH) Management (Mllll)
'Cans,ervation (MWH)
2008: 211 2,344 7 2,344
AEPJPSO
2009 33 20,300 5 20,300
2008 9 6,889 B 5,194
Empire
2009 10 9,525 B 7,923
2008 15 0 10 0
GRDA
20019 15 0 10 01
2008 0 0 0 0
KAMO
2009 0 a. 0 a.
2008 1133 0 46 6.446
OG&E
2009 145 0 193 46,5.23
2008 0 0 0' 0
OMPA
2009 0 0 a. 0
200.8 65 0 50 0
WFEC
20.09 65 0 50 0
200H 243 9,233 121 113,984
TOTAL
2009 268 29,825 26·6 74,746
41
Generation System Operations by the
Providers
Table 3-10
Annual System Operations Data for the Providers
A B C 0 E F G H I J K L M II 0
Actual Total Total System Total Lowest
Ilet System Actual System Average System Production System Resel"\re
Ilet Energy System Peak System System Production Cost-fuel & Capital Per Unit Margin
System Generation Energy Power Capacity Average Cost lIon- Purchas,ed Recovery Total System Cost for Du~ingthe Customer
Provider Year Capabinty Capability Generation Demand Factor Heat Rate Fuel Pow.er Cost Revenues Generation Year Meters
(MW) (MWH) IMWH! (MW) (%) (MBtul SO SO SO ($JMWH) (%)
KWH!
2008 4,405 38,587,800 14,875,057 4,200 39.57% 10.057 5248,018 $1,052,519 $258,821 $1,643,042 S105 13.90% 574.269
AEPIPSO
2009 4,410 38,631,600 13,966,152 3,994 36.51% 10.100 $293,595 $570,155 $243,057 $1,120,475 $79 23.30% 577,759
2008 1,419 12,264,000 3,862,612 1,152 36.10% 9.816 $27,856 5182,518 5118,534 $409,794 $89 22.91% 217,410
Empire
2009 1,426 13,245,120 3,737,688 1,085 32.20% 10.340 516,672 $170,311 $121,385 $411,975 $93 30.44% 217,254
2008 1,553 12,463,290 7,270,874 1,177 58.34% 6.549 $64,358 $128,680 $153,336 $323,747 $49 30.83% 130,216
GRDA
2009 1,836 15,400,080 8,055,828 1,399 52.31% 7.027 576,212 $138,546 $121,853 5317,669 S44 24.77% 132,249
2008 2,087 18,283,465 10,084,632 1,870 55.00% 10.908 $124,626 $184,427 $46,656 $355,708 $33 11.00% 326,283
KAMO
2009 1,857 16,268,969 8,607,394 1,643 53.00% 11.073 $126,596 $145,029 $38,857 $310,482 $33 13.00% 326,087
2008 6,606 57,868,560 32,058,870 5,567 55.40% 10.118 $187,058 $1,122,730 $370,129 52,036,214 $68 18.64% 702,378
OG&E
2009 7,094 62,143,440 30,254,293 5,958 48.68% 9.895 $1991,907 $801,418 $462,791 51,841,268 563 19.07% 709,081
736 4,189,968 1,916,712 658 45.75% 8.895 $8,861 $96,524 $36,946 $151,053 $64 11.85% Not
2008 Provided
OMPA
Not
2009 816 5,457,480 2,146,584 677 39.33% 7.482 $11,907 $68,228 $42,407 $147,670 $56 20.53%
Provided
2008 1,205 8,637,000 4,650 1,476 53.84% 10.712 $24,361 $321,311 $74,749 $43,821 $47 0.54% 269,593
WFEC
2009 1,340 9,583,000 4,608 1,444 48.19% 10.728 $27,191 $224,132 $68,427 $341,298 $35 12.57% 272,871
42
CHAPTER FOUR
PROVIDER PROJECTIONS AND FORECASTING METHODS
This chapter presents the forecast projections and forecasting methods as stated by
each of the seven Providers for the years 2010 through 2019.
Table 4-1 reflects a statewide estimate of the capacity margin for the Providers from
2010 through the year 2019. The table shows the relationship of the state's electric service
Providers' projected annual generation capacity to their projected annual demand.
Allowing for a cushion of 12 percent reserve margin as prescribed by the Southwest Power
Pool, the capacity in excess of 12 percent varies considerably for the projected period.
All Providers have supplied data for their existing and proposed transmission
facilities as well as any new and/or upgraded substations. Not only is there a need for new
transmission facilities and substations, many transmission lines and substations will need
upgrading in order to serve Oklahoma's growing electrical power consumption, especially
those related to new wind energy resources.
The Providers' forecasting techniques and methodologies range from econometric
forecasting to end-use modeling as performed by OG&E and AEP/PSO. Chapter Four
describes each provider's forecasting techniques and methods.
43
Projections for the Next 10 Years (2010 through 2019}
Table 4-1 reflects a statewide estimate of the capacity margin of the state's electric
Providers annually for the years 2010 through 2019. The table shows the relationship of the
state's electric service Providers' projected annual generation capacity to the Providers'
projected annual demand. The Southwest Power Pool prescribes a cushion of 12 percent
capacity margin. Capacity in excess of this 12 percent varies considerably for the projected
period. Providers seem to be relying more heavily on wholesale purchased power than on
new construction in generation facilities or purchase of existing generation facilities; however,
both OG&E and AEP/PSO have made additions to their systems, generally limited to
generation by natural gas powered facilities. Additionally, the Providers anticipate an
increase in peak demand from 16,196 MW in 2010 to 18,228 MW in 2019 for a growth rate of
12.55 compared to the projected growth rate of 15.3% found in the 2008 Electric System
Planning Report. The Providers anticipate a growth rate of only 3.62% for the maximum
available capacity generation for the years 2010 through 2019 compared to the ten year
projection of 19.43% in the previous report.
44
Table 4-1
Projeetions Of Maximum AUow,able Demand ForYe,ars, 2010 Thru201'9 by Providers (megawatts)
A B C D E f G HI I J K L M
Maxi:m,um,
Avail'able firm, P.eak Demand ~l,et Requi.r,ed Required CB!paci;." in
Y,ear Ca:paci,ty Capacity ToOtall Demand Side S},st,em CB!paci,ty Capacity Capacity Capacity exces.s of
(Generation) p.urchases Capa;ci,ty( Forecast ProOgrams Demand Mar'gin Margin Mar,gin Mar,gin 12%
(MViJ') (L\Ollil) MW) (MW) (PJ.lW) (MVi/) (••OW) (%) (MW) t%,) (MW)
(C+D) (f-'G) (E-H) (II E) (H~.38)-H II-K)
lio~all 2010 10,.327 2,98;8 19,315 1!o',1916 276 15,920 3,395 17.60% 2,1711 12.00cJ6, 1.224
Total 2011 15,443 2,89'8 19',341 15,480 334 15,146 3,195 15.50% 2,202 12.0'0% 9'94
liotal 2012 16,462 3,325 19',787 116,595 4913 16,1012 .3,685 118.,60% 2,196 12.00% 1,48:9
Total 2013 15,480 3,38.5 19',865 16,869' 613 15,256 3,510 18.20% 2,217 1.2.00% 1,393
1I01al 2014- 16,432 3,430 1,9,863 17,090 755 16,335 3,528 17.80% .2,227 12J)Or% 1,301
Total 2.015 15,537 3,340 19',877 17,285 825 16,459 3,418 17.20% 2,244 12.00% 1,174
li01al 20116 16,537 3,337' 119,874 117,508 862 16,646 3,228 16.20% 2,270 12.00% 958
Total 2017 15,795 3,39'0 20,185 17,755 879 16,877 3,309 16.40% 2,301 12.00% 1,0.0.8
liotal 20118 16,91191 3,396 20,31.5 17,986 8:99 17,0187 3,228 115.90% 2.330 112.00% 898
Total 20.19 16,9191 3,39'9' 20,319 18,228 9'04 17,324 2,994 14.70.% 2,362 12.00.% 632
REGIONAL BULK POWER TRANSMISSION FACILITIES
This section provides data on the statewide existing and proposed transmission facilities and substation upgrades.
Electric transmission lines carry electric energy from generating facilities to local communities. A distribution substation
reduces this high-voltage energy and transfers it to lower-voltage distribution lines, which carry the energy to individual
houses and businesses. In Oklahoma, transmission lines range in size from 69 kilovolts (kV) to 345 or 765 kV. Many
existing transmission lines will need upgrading over the next decade. Many new transmission lines and substations will
45
also be needed to serve Oklahoma's growing electricity use.
T ansmission LineCosts Forecast 2010 - 2019
350
• I I. - - • •
.AEPjPSO
• EMPIRE
.GRDA
KAMO
.OG&E
.OMPA
.WFEC
300
250
200
lime Cost ($M)
ISO
100
50
o
2010 2011 2012 2013 2014 2015 2015 2017 2018 2019
All the Providers, with the exception Empire District (which has planned no new transmission investment in
Oklahoma for years 2010 through 2019), have given investment estimates of their proposed and existing transmission
lines. (See page 34)
When more transmission capacity or service is needed in an area, two options are available to the Providers these
options are: 1) to upgrade existing transmission lines whenever possible, rather than to build new transmission
46
lines, and 2) to build new electric transmission lines where existing lines are not located.
The alternative to the first goal is to acquire many miles of new right-of-way in new
locations.
Transmission line owners will need to make major upgrades to the electric
transmission line system over the next decade. This is due to a number of factors, including
the age of existing facilities, increased electricity use by a growing Oklahoma population,
and the change in national regulation of utilities.
Power-line lengths are important in the transmission network. Although cost
estimates, service dates and line lengths are subject to change, OG&E proposes significant
transmission line additions in each of the next five years with major additions
(approximately $322 Million) occurring in 2012. AEP/PSO proposes major transmission
additions in 2013 and 2014 at a projected cost of $150 million. WFEC plans to invest
approximately $42 million in transmission facilities during 2010 and 2011, and KAMO plans
to invest approximately $75 million in transmission facilities during the next four years.
GRDA plans to make a $10 million investment in new transmission facilities during 2010.
47
LimeMiles 150
Transmlission Lines Forecast 2010 - 2019
300 -
I
!
I
!
•
J
-!..-
I
I
_I
I
I J
I I. I I
J I
I
I
I
J
- - • • ..,
.AEPjPSO
• fer""P'IRfe
.GRDA
KAIMO
.OG&IE
.OIMPA
.'uVFEC
250
200
10;0
50
o
2010 2011 2012 2013 2014 20]LS 2016 2017 2018 20]['9
48
$50.00
$45.00
$40.00
~ $35.00
~
-••• $30.00 '"8
$25.00 I:
.-Si -!II $20.00 I~=I $15.0-0
$10.00
$5.0-0
$0.00
5 bstati 0 Costs Forecast 2010 - 2019
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
.AEP/PSO
• EMPIRE
.GRDA
KAMO
.OG&E
.OMlP'A
.WfEC
Substations transform the voltage from higher level transmission voltages to lower level distribution voltages, which is
necessary to lower the voltage of electricity to provide safe and effective power for homes and businesses. Statewide
proposed and existing substations ranged from 69kv to 161kv. Individual investment estimates and proposed service
dates vary considerably; however, over the next 10 years Providers plan to invest approximately $370M in new substations
and upgrades to existing substations.
49
Peak Capacity Forecast
Table 4-2
Statewide Peak Capacity By Resource Type for Years 2010 Thru 2019 for the Providers (megawatts)
A B C D E F H G H
Purchased
Provider Year Coal Uatural Gas Oil Hydro Renewables Power Total Capacity
(MWI IMW) lMW} IMW) (MW) IMW) (MW)
Total 2010 6,.329: 10,75B 38 888 29 1,273 19,314
Total 2011 6,438 10,936 38 888 29 1,023 19,351
Total 2012 6,455 10,937 3B 892 44 1,438 19,803
Total 2013 6,502 10,916 38 892 44 1,491 19,882
Total 2014 6,451: 10.916 38 896 44 1.537 19,882
Total 2015 6,500 10,970 38 896 44 1,448 19,896
Total 2016 6,490 10,969 38 896 44 1,456 19,893
Total 2017 6,481 11,234 38 896 44 1,513 20,206
Total 201'8 6,388 11.447 38 896 44 1,522 20,334
Total 2019 6,382 11,446 38 896 44 1,531 20,337
The statewide peak capacity by resource type for years 2010 through 2019 shows
the Providers' collective forecast in Oklahoma and reflects a gradual increase year by year
through 2019.
50
Forecast Analysis
Staffs Comparison of Forecasting Projections Against Actuals
11th ESPR 10th ESPR 9th ESPR
(Actuals from (Forecast from (Forecast from
Table 3-3) Table 4-1)1 Variance % Table 4-1)2 Variance%
2008
Adjusted Peak Demand (MW) 16,125 14,038 14.87% 14,000 15.18%
Reserve Margin With Purchases 14.46% 14.30% 1.12% 1.2.98% 11.40%
System Capabiltiy (MW) 18,457 14,256 29.47% 14,076 31.12%
Peak Power Purchases (MW) 2,386 2,124 12.34% 2,014 18.47%
2009
Adjusted Peak Demand (MW) 16,223 14,416 12.53% 14,208 14..18%
ReseNe Margin With Purchases 18.16% 15.31% 18.62% 12.04% 50.83%
System CapabHtiy (MW) 19,169 15,158 26.46% 14,076 36.18%
Peak Power Purchases (MW) 1,977 1,854 6.06% 2,078 -4.86%
1 Forecast data came from the Tenth Electric System Planning Report covering years 2005 through 2007.
2 Forecast data came from the Ninth Electric System Planning Report covering years 2003 and 2004.
Oklahoma's forecasted data from the Ninth and Tenth ESPR Reports were
compared with the current ESPR report. The adjusted peak demand for 2008 and 2009
were higher than previously forecasted for either of the two previous reports. System
capability was, in all cases, higher than previously forecasted.
51
Provider Forecasting Methods
This section describes the methods used by the Providers for developing their
forecasts.
OG&E
General Methodology
OG&E employs Quantec, an economic consulting company, to produce the long-term
energy and peak demand forecast. Quantec uses an econometric approach with five
years of historical OG&E hourly loads to estimate the utility's peak demand model. OG&E
purchases an economic forecast for the states of Oklahoma and Arkansas that Quantec
uses to drive the OG&E hourly peak demand forecast.
Quantec produces a 10-year hourly peak demand forecast for the OG&E system.
The approach taken by Quantec uses a single equation with separate intercept and slopes
for each hour of the day by day type (weekday and weekend). The model includes the
following explanatory variables:
• Hourly intercepts
• Hourly temperature terms
• Hourly temperature terms interacted with model variables
representing additional August cooling load, beginning in 1999, associated
with earlier school district starting dates
• Economic growth as approximated by real personal income
• Hourly heat buildup terms capturing the effects of weather patterns
that extend over several days (e.g., heat waves)
• The square of hourly heat buildup terms
In constructing peak demand forecast, Quantec used the last 27 years of weather
data to develop a probabilistic forecast of peak demands. This approach helps the
52
company to assess the risk associated with different weather events that the company
might encounter.
AEP/PSO
KWh Forecast Process
Regression models with time series error terms were used to forecast kWh sales up
to 18 months ahead (short-term). These models use the most recent customer count, kWh
sales, weather (as measured in degree days), and other variable indicators where needed.
Weather variables are calculated from data obtained from the National Oceanic and
Atmospheric Administration (NOAA). Models for each revenue class (residential,
commercial, industrial, other retail, wholesale) and for some specific large customers are
estimated and evaluated.
Statistically Adjusted End-use (SAE) models are used for forecasting long-term
residential and commercial kWh sales. SAE models are econometric models with features
of end-use models included to specifically account for energy efficiency impacts, such as
those included in the federal Energy Policy Act of 2005 (EPACT 2005). SAE models
include the construction of structured end-use variables that embody end-use trends,
including equipment saturation levels and efficiency. Factors are also included to account
for changes in energy prices, household size, home size, income, and weather conditions.
Moody's Economy.com forecasts of these regional variables are used as drivers.
Regression is used to estimate the relationship between observed customer usage and the
structured end-use variables. The result is a model that has implicit end-use structure, but
is econometric in its model fitting technique.
Quarterly econometric models are used for forecasting long-term industrial, other
retail, and wholesale kWh sales, The process uses an economic forecast provided by
Moody's Economy.com for the United States as a whole, each state, and regions within
each state, where appropriate. These forecasts include projections of employment,
population, industrial production, and other demographic and financial variables. The long-term
forecasting process incorporates these economic projections and other inputs to
53
produce a forecast of quarterly kWh sales. Other inputs include regional and national
economic and demographic conditions, energy prices, weather, and customer-specific
information.
The results of the short-term and long-term models gradually combined 12 to 18
months into the forecast horizon. During the initial stages of forecast development, the
short-term and long-term values are weighted and combined. Ultimately, the short-term
weights decrease and the long-term weights increase until the short-term weight is zero
and the long-term weight is one. At this point, the forecast results are purely from the long-term
process.
The separate steps take advantage of the relative strengths of each method. The
regression models used in the shorter-term modeling employ the latest available sales and
weather information to represent the variation in sales on a monthly basis for short-term
applications. While these models produce accurate forecasts in the short run, without
specific ties to economic factors, they are less capable of capturing the structural trends in
the electricity consumption that are important for longer-term planning. The long-term
modeling process, with its explicit ties to economic and demographic factors, is appropriate
for longer-term decisions and the establishment of the most likely or base load and demand
outcome over the forecast period.
Hourly Load, Peak Demand, and Losses Forecast Process
To forecast peak MW, historical load and temperature data is used to develop
hourly load representations (load shapes) for specific temperature increments. This data is
also used to develop daily energy models using regression techniques. These regression
model results are applied to a forecast of typical weather to generate a daily energy
forecast. This forecast is benchmarked to the aggregation of the class sales forecast plus
losses, and the load shapes are applied to the daily energy forecast to produce an hourly
load and peak MW forecast. The peak MW forecast is also bench marked to the historical
load factor relationship between peak demand and energy load using weather normalized
values.
54
GRDA
The GRDA forecast was produced from a "bottom-up" approach, with the results
summed to produce a forecast of GRDA's total energy sales and system peak demands.
The process used to develop individual forecasts included econometric techniques.
In cases where valid regression equations could not be determined, judgmental analysis
was applied to forecast energy sales. The average historical loss factor was applied to the
vector of forecasted future sales to forecast the future energy requirements of the GRDA
customer. For retail customers directly served by GRDA and for municipal customers
whose sales were unknown, system energy requirements were forecasted using
judgmental analysis.
Historical energy requirements were compared to annualized 30-minute non-coincident
peak (NCP) demands to compute load factors for each customer. Historical
average load factors were then applied to the forecasted vectors of energy requirements to
project the future NCP demands of GRDA's various loads, with judgmental adjustments
made as needed to account for the addition of expected loads on the system.
Historical coincidence factors were applied to each customer's forecasted vector of
NCP demands to forecast the future contribution of the customer to GRDA's system peak.
OMPA
General Methodology
OMPA uses a city-by-city forecast generated by a multiple linear regression model
with the Consumer Price Index as the primary driver. The individual forecasts are summed
and then corrected to a forecast of OMPA as a whole. The forecast is also a weather-normalized
multiple linear regression model.
55
WFEC
General Methodology
For WFEC's generation, transmission and financial planning, each member load
forecast is developed independently using econometric method. These forecasts added
together determine integrated forecast of WFEC.
Econometric equations are developed to determine the expected annual usage of
kWh for the different classes of consumers for each member distribution cooperative.
Trending, averages, and judgment have also been used for mark-ups, losses, miles of
lines, load factor, and diversity if required to develop summer and winter MW demands.
The following economic, demographic, and weather factors affecting the load
requirements are considered in economic model development:
County Population
County Per-capita Income
County Farm Employment
County Non-farm Employment
Area Heating Degree Days
Area Cooling Degree Days
Area Evaporation
Area Precipitation
Price of Electricity
Price of LP Gas
Price of Oil
Electric Heat Saturation
Air-conditioning Saturation
Household Size
County level data were converted to service area data using appropriate weights to
represent county participation. The historical data were obtained from Regional Economic
56
Information System, U.S. Bureau of Economic Analysis (BEA) and projected data from
National Planning Associate (NPA). Weather data were obtained from the weather station
representing the co-operative from the National Climatological Survey monthly publications.
Historical oil and LP gas prices were obtained from Petroleum Marketing Monthly and
Natural Gas Monthly published by the U.S. Department of Energy's Energy Information
Administration and projected data from Data Resources Inc. (DRI). Saturation and
household size data were obtained from co-operative consumer surveys conducted from
time to time. Price of electricity and various markups and other information were obtained
from U.S. Rural Utility Services (RUS) Form 7.
Empire District
General Methodology
Empire uses least squares regression analysis to forecast demand and energy by
month using 12 years of historical data.
1. Regression Analysis (least squares) used to forecast energy (NSI)
Net System Input (energy) is forecast with linear regression. The independent
variables are customer count and weather. Weather is expressed as heating-degree
days (HOD) or cooling-degree days (COD) with a base of 65 degrees. Total degree-days
are used in an annual regression. In a monthly regression, HODs are used in
the winter months, COOs are used in the summer months, and the spring and fall
months may use a combination of HODs and COOs or only one depending on which
provides the best correlation to actual usage. The initial regression equations are
developed with about 1D to 12 years of history. To project future usage, the
regression equation is used with projections of future customer counts, and "normal"
weather. Normal weather is based on a 3D-year average.
y = a + bX1 + CX2
a = intercept
57
b = customer number
c = HOD / COD (base 65)
X1,X2= variable coefficients
2. Regression Analysis (least squares) used to forecast peak demand
The monthly and annual peaks are forecast with linear regression. The
independent variables for the winter months (January-May, October-December) are
customer count and temperature at the peak hour. The independent variables for
the summer months (June-September) are customer count and three-day weighted
average temperatures (70% day of peak, 20% one day prior, and 10% two days
prior). To project future usage the equation is used with projections of future
customer counts and either average temperature at the peak hour or average three-day
weighted average temperatures at the peak day, depending on the month.
y = a + bX1+ CX2
a = intercept
b = customer number
c= 3DWTHI
X1,X2= variables coefficients
3DWTHI = 0.7(THI Day of Peak) + 0.2(THI Day of Peak -1) + 0.1 (THI Day of
Peak -2)
Note that the Three Day Weighted Temperature Humidity Index (3DWTHI) is only
used in the summer months (June - September). The temperature at time of peak is used
for the rest of the year.
KAMO
General Methodology
58
Loads are projected using a linear regression model that uses weather normalized
historical information back to 1987. The resource forecast is determined by using a
chronological model that calculates the operational cost of various asset combinations that
meet those load requirements. Fuel projections, operations and management projections,
and capital cost are all used in this assessment. Fixed costs are gathered from industry
sources and the Energy Information Administration. The set of assets that reliably serves
the load requirements at the least cost is recommended to the Board of Directors.
59
Conclusion
In this report the Commission's Public Utility Division Staff has made every effort to
present factual information concerning the state's most significant electricity Providers.
There are other electric providers in the state which are not specifically listed in this report;
however, generally the energy they produce is capatured in the purchased power of the
seven Providers who are the primary focus of this report. Although certain projections are
made over the next 10 year period, the information in this report relates primarily to the
electricity Providers who most directly impact the citizens of the state, their generation
systems, their physical capacities to meet energy demands, and the costs of providing such
electric generation.
Renewable energy resources did not show any appreciable changes since the last
Electric System Planning Report was published. Staff's projects that the next report, 2012,
should indicate significant changes in renewable energy generation. Much of the
renewable generation we have in 2010 was under development during the years covered
by this report.
Table 3-2 shows the capabilities of the self-owned generation facilities of the
Providers by various types of fuel sources. Table 3-3 shows the peak demands placed on
these systems during 2008 and 2009 along with the amount of purchased power required
to meet the total system demand during peak periods. Comparing these peak demands to
facility capacities indicates the reserve margins available for each of the major Providers,
both with and without power purchases.
Over the last several years, all electricity Providers have sustained a steady growth
in the demand for their power. Furthermore, except for the purchase of the 1,200 MW
Redbud plant by OG&E, GRDA and OMPA, no Provider had any substantial increase in its
generation facilities over the study period. In several cases minor increases in the capacity
of existing facilities resulted in actual capacity margins to increase since the Commission's
last report. During the report period, electric providers continued to rely heavily on power
purchases, but margins without purchases improved over the last reporting period. By
2009 the total capacity of the providers including purchases increased by 22% over 2007
and without the Redbud facility capacity still increased by almost 15% in a two year period
60
This Electric System Planning Report also includes information (depicted in graph
form) which demonstrate the planned additions and upgrades to the Providers transmission
facilities and substations. Staff recognizes these proposals and upgrades' are significance
in the planning of Oklahoma's future growing electricity use. Many existing transmission
lines will need upgrading over the next decade. New transmission lines and substations
will also be needed to serve Oklahoma's electricity needs. Many of these additions and
upgrades are driven by the significant growth in western Oklahoma's wind energy.
Glossary
BTU - British thermal unit - A traditional unit of heat energy equal to about 1.06
kilojoules It is approximately the amount of energy needed to heat one pound of
water one degree Fahrenheit. Theoretically, 3412 BTU = 1 kilowatt hour.
The unit MBTU was defined as one thousand BTU presumably from the Roman
numeral system where "M" stands for one thousand (1,000). This is easily
confused with the SI mega (M) prefix, which multiplies by a factor of one million
(1,000,000). To avoid confusion many companies and engineers use MMBTU to
represent one million BTU. Alternatively a therm is used representing 100,000 or
105 BTU, and a quad as 1OA15BTU.
Capacity - A measure of the quantity of power; the amount of electric power delivered or
required for which a generator, turbine, transformer, transmission circuit, station, or
system is rated by the manufacturer.
Capacity Margin Percentage - (capacity - load)/capacity Under SPP rules, this is 12%
Demand - The amount of power required to meet the customer's load at a given instant or
averaged over any designated interval of time, expressed in kilowatts or megawatts.
Distribution - The delivery of electricity to a retail customer's home or business through
distribution wires or facilities of regulated public utilities.
61
Energy - The capacity for doing work. In the context of electricity rates and services, the
word "energy" refers to electrical energy. In this sense, energy is a measure of the
quantity of units of electricity used in a given time period, measured in kilowatt hours.
Federal Energy Regulatory Commission (FERC) - The U.S. government agency that
regulates the price, terms, and conditions of transmission services and wholesale
sales of electricity. For example, FERC sets and enforces the wholesale electric rates
that investor-owned utility generators charge their wholesale customers. FERC also
licenses hydroelectric projects.
Generation - The process of producing electricity by converting other forms of energy into
electricity. Gigawatt (gW) - One gigawatt equals one billion (1,000,000,000) watts, or
one million (1,000,000) kilowatts, or one thousand (1,000) megawatts.
Gigawatt-Hours (gWh) - One gigawatt-hour equals one billion (1,000,000,000) watt-hours,
or one million (1,000,000) kilowatt-hours, or one thousand (1,000) megawatt-hours.
Independent System Operator (ISO) - A neutral party responsible for the management
and control of the electric transmission grid in a state or region.
Investor-Owned Utility (IOUs) - A stockholder-owned utility company that provides public
utility services to retail customers for a profit.
Independent Power Producer (lPP) - Any person who owns or operates, in whole or in
part, one or more independent power production facilities. IPPs are not owned by
utilities that serve retail end users.
Kilowatt (KW) - One kilowatt equals 1,000 watts.
Kilowatt-Hour (kWh) - This is the basic unit of measure for electric energy equal to one
kilowatt of power supplied to or taken from an electric circuit steadily for one hour. One
kilowatt-hour equals 1,000 watt-hours.
Megawatt (MW) - One megawatt equals one million (1,000,000) watts or One thousand
kilowatts (1,000 kW).
Megawatt-hour (MWh) - One megawatt-hour equals one million (1,000,000) watt-hours.
62
Purchase Power Agreement - A contract specifying the terms of power purchased.
Firm Power - Power or power-producing capacity intended to be available at all times
during the period covered by a guaranteed commitment to deliver, even under
adverse conditions. On option is a take or pay agreement where the purchaser must
pay even if he does not take the delivery of power. Another option is a reserve power
agreement, where the purchaser pays the capacity charge but not the energy charge
unless he actually takes delivery.
Non-Firm Power - Power or power-producing capacity supplied or available under a
commitment having limited or no assured availability.
Reserve Power - Power which is immediately available (like a reserve generator).
Spot Power - A single shipment of Purchased power scheduled in advance for delivery
within a year
Capacity Charge - An element in a two-part pricing method used in capacity transactions
(energy charge is the other element). The capacity charge, sometimes called Demand
Charge, is assessed on the amount of capacity being purchased, while the energy
charge is assessed on the energy actually delivered.
Regional Transmission Organization (RTO) - An organization that is independent from
all generation and power marketing interests and has exclusive responsibility for
electric transmission grid operations, short-term electric reliability and transmission
services within a multi-state region. To achieve those objectives, the RTO manages
transmission facilities owned by different companies and encompassing one, large,
contiguous geographic area.
Reserve Margin - The difference between net system capability and system maximum
load requirements (peak load or peak demand).
Reserve Margin Percentage - (capacity- load)/load Under SPP rules, this is 13.6%
SPP - Southwest Power Pool
63
Substation - An assemblage of equipment for the purposes of switching and/or changing
or regulating the voltage of electricity. Service equipment, line transformer installations
or minor distribution and transmission equipment are not classified as substations.
Transmission - The bulk transport of high-voltage power, typically over longer distances,
between generating plants and distribution systems.
Watt - A unit of measure of electric power.
Wind Energy I Wind Generation - Electricity generated through wind-powered turbines.
64

C 5600.3 E38 2010 c.1
~ Iate of Oklahoma
Eleventh
Electric System Planning Report
Prepared by the Oklahoma Corporation Commission's Public Utility Division
December 2010
Oklahoma Corporation Commission
Electric System Planning Report
December 2010
Table of Contents
PAGE
EXECUTIVE SUMMARy 1
CHAPTER ONE: PREFACE AND INTRODUCTION 5
CHAPTER TWO: PROVIDER OVERVIEWS 7
CHAPTER THREE: ANNUAL ELECTRIC SERVICES SYSTEM OPERATIONS 26
TOTAL GENERATION AND POWER PURCHASES TABLE 3-1 27
TOTAL ENERGY GENERATION CAPABILITY TABLE 3-2 28
ACTUAL PEAK DEMAND DURING 2008 AND 2009 TABLE 3-3 29
ACTUAL ENERGY AVAILABLE FOR 2008 AND 2009 TABLE 3-4 30
GENERATION SYSTEM CAPABILITy 31
GENERATION SYSTEM RELIABILITY 32
GENERATION SYSTEM EFFICIENCY 33
GENERATION FUELS 35
SYSTEM FUEL USE AND COST 36
TABLE 3-5 37
ELECTRIC SYSTEM COST................................................................................................... 38
SYSTEM COSTS TABLE 3-6 38
POWER PURCHASES 39
PURCHASED POWER QUANTITY AND COST TABLE 3-7 39
FIRM CAPACITY AND RESERVES PURCHASES AND COST TABLE 3-8 40
DEMAND SIDE MANAGEMENT (DSM) PROGRAMS 40
DSM PROGRAM POTENTIAL & ACTUAL SAVINGS TABLE 3-9 41
GENERAL SYSTEM OPERATIONS BY THE PROVIDERS TABLE 3-10 42
CHAPTER FOUR: PROVIDER PROJECTIONS AND FORECASTING METHODS 43
PROJECTIONS FOR THE NEXT 10 YEARS (2010 THROUGH 2019) 44
STATEWIDE MAXIMUM ALLOWABLE DEMAND TABLE 4-1 45
REGIONAL BULK POWER TRANSMISSION FACILITIES 45
PROPOSED TRANSMISSION LINES - LINE INVESTMENTS 46
PROPOSED TRANSMISSION LINES - LINE MILES 48
PROPOSED SUBSTATIONS INVESTMENTS 49
PEAK CAPACITY FORECAST TABLE 4-2 50
FORECAST ANALySiS 51
PROVIDER FORECASTING METHODS 52
CONCLUSiON 60
GLOSSARY 61
This report was prepared in accordance with Title 17 Okla. Stat., § 157, which requires the Oklahoma
Corporation Commission to prepare a ten-year assessment of the electrical power and energy requirements
of this state and assess the need for additional or replacement generating facilities and the associated costs
of such facilities to the electric consumers of this state. The Commission shall reassess the statewide future
electrical generation requirements every two (2) years. Such assessments shall not constitute official
Commission certification or approval of any proposed generating facilities.
This publication, printed by the Oklahoma Corporation Commission is issued by the same as authorized by
Title 17 Okla. Stat., § 157. Forty copies have been prepared and distributed at a cost of $294.80. This
publication may also be found on the Oklahoma Corporation Commission's website at www.occeweb.com
under the Industry / Electric Utility tab.
ii
EXECUTIVE SUMMARY
The State of Oklahoma has seven major electric suppliers operating in the state. Of
these seven suppliers, six actually own and/or operate electric generation facilities, or
portions of generation facilities within the borders of Oklahoma. These seven electric
suppliers are collectively referred to as the Providers in this report. The Providers'
generation systems have wide variations in their power and energy production capabilities.
These Providers do not include any of the states smaller regulated or non-regulated electric
cooperatives or any of the wind energy suppliers generally located in western Oklahoma.
This report also does not include the Independent Power Producers (IPP), such as AES
Shady Point and Calpine. Nor does the report include detailed information regarding the
Southwestern Power Administration. Most of the power generated by these IPPs is
typically accounted for in the power purchase totals of the seven Providers.
Oklahoma Gas & Electric (OG&E) is the largest Provider in the state as well as the
largest investor owned (IOU) electric utility in Oklahoma, in terms of generation capacity,
energy generation capability and retail customers followed by American Electric Power
Company/Public Service Company of Oklahoma (AEP/PSO). Grand River Dam Authority
(GRDA) and Western Farmers Electric Cooperative (WFEC) are essentially identical in
terms of their generation capacity and energy generation capability. Next is KAMO and the
Oklahoma Municipal Power Authority (OMPA) who are similar in their capacity totals;
however OMPA purchases nearly one-third of its capacity while KAMO self generates
almost 90% of their required capacity, which it sells to Associated Electric Cooperative Inc.
(AECI). Only Empire District Electric (EDE), who has approximately 4,700 customers in
Oklahoma, has no generation facilities located in the state. All of Empire District's
generation facilities are located in the states of Missouri, Kansas and Arkansas. Empire
District is the smallest investor owned electric utility operating in Oklahoma; however,
Empire does have over 168,000 electric customers throughout its system. EDE is
significant in terms of its total generation with approximately 1,400 MW of total capacity.
The statewide electric capacity reserve margins for 2008 and 2009 were 14.49%,
and 18.16% above immediate need, respectively, when purchased power was included.
Based only on Provider generation capacity, the statewide reserve margin for 2008 and
1
2009 were -0.34% below need and 5.97% above need, respectively. The reserve margins
for 2008 and 2009 indicate that there existed insufficient generation capability to meet
statewide peak demand without purchasing power or implementing demand reduction
programs. See Table 3-3 for details.
If generation system efficiency is measured in terms of the kilowatt hours (kWh)
delivered to the consumer, other factors may affect the efficiency of the system as a whole.
Among these are the design and operation of the transmission system delivering power
from generation units to the distribution system, the design and operation of the physical
interconnections which tie the generation units, transmission system, and distribution
system together, and the design and operation of the distribution system which actually
delivers electrical energy to consumers.
The per megawatt hour (MWh) total delivered cost of generation and purchased
power for the individual Providers varies considerably. For 2008 the range was from
KAMO's $35.27/MWh to Empire District's $89.41/MWh. The range for 2009 was from
KAMO's $36.07/MWh to Empire's $92.93/MWh. See Table 3-6 for details.
The average cost of fuel for the Providers in 2008 was $3.62/MMBtu and
$2.57/MMBtu during 2009. The average cost of fuel per MWh generated in 2008 was
$34.99 and $24.63 in 2009. See Table 3-5 for details.
Several of the Providers purchased power from outside their generation systems.
These purchases are divided into two broad categories. The first category includes
purchases from the Southwestern Power Administration (SWPA), a federal agency that
markets power generated by hydroelectric projects, some of which are located in
Oklahoma. SWPA operates hydro facilities on several Oklahoma reservoirs and lakes
including; Lakes Broken Bow, Eufaula, Fort Gibson, Keystone, Robert S. Kerr, Tenkiller
and Webber Falls. The other category includes purchases from non-utility power
producers, both those certified by the Federal Energy Regulatory Commission (FERC) as
"Qualifying Facilities" (QF) under the federal Public Utility Regulatory Policies Act (PURPA)
and other non-utility power producers such as GRDA and AECI.
All of the Providers have supplied data on their existing and proposed transmission
facilities and substation upgrades. Many existing transmission lines will need to be
2
upgraded over the next decade. Many new transmission lines and substations will also be
needed to serve Oklahoma's growing demand for electrical energy. Transmission issues
will continue to dot the horizon like the many new wind turbines that new transmission
facilities support. There are cost recovery issues which regulators must address as well as
siting concerns on the part of landowners which could delay the full development of
western Oklahoma's extensive wind resource. Western Oklahoma's wind energy which will
not only contribute to Oklahoma's growing energy requirements, but will provide a boost to
Oklahoma's economy through wind related jobs. Other states with less renewable
opportunities will also benefit from Oklahoma's wind, assuming that transmission facilities
will be in place to support this valuable Oklahoma resource.
Over the last several years, collectively, all electricity Providers have sustained a
somewhat constant level of demand with periods of minor growth as well as periods of
minor decline in the demand for their power.
19,0000
...•.
.•. /
~
~
~ -- ~ Peak Demand
Peak Demiand
20,500
17,50-0
16,000
14,500
13.000
:n.500
1999 2000 20001 2002 2003 2004 2005 20006 2007 20DB 20D9
Note: The increase in 2008 and 2009 over 2007 is primarily due to the change in reporting of all Providers from Oklahoma only demand
to total system demand, otherwise the peak demand continues to be fairly stable.
Other than minor capacity additions related to wind generation, the only major
addition to the Providers' generation resources was the 1230 megawatt Redbud natural
gas facility near Luther, Oklahoma. In 2009 OG&E (51%), GRDA (36%) and OMPA (13%)
3
purchased the Redbud facility, which was previously owned by Kelson Energy and was
providing purchase power to Oklahoma IOUs and cooperatives. In aggregate the reserve
margin of the Providers has continued to improve over the last five years even considering
the rather significant dip in the margin in 2006.
The Providers continue to rely heavily on power purchases to meet the reserve
standards established by the Southwest Power Pool. However, almost all the Providers
operate or have plans to operate some type of demand-side management (DSM) or
demand-response programs.
4
CHAPTER ONE
PREFACE AND INTRODUCTION
This is the eleventh edition of the Electric System Planning Report (Report) prepared
by the Oklahoma Corporation Commission's Public Utility Division Staff (Staff). The current
report is the accumulation and assimilation of extensive statistical data submitted to the
Commission Staff by the major electric Providers in Oklahoma. Data gathered for this
presentation is based on the years ending December 2008 and 2009, and projections from
this data look to the next 10 years. Many resources were utilized to procure this
information including, but not limited to the following: Provider and various other websites,
brochures, and annual reports, along with company, state and federal jurisdictional filings,
and responses to information requests provided by the Providers as well as follow-up
discussions with industry personnel.
The report was prepared in accordance with 17 Okla. Stat., § 157, which requires
the Oklahoma Corporation Commission to prepare and publish an assessment of electrical
power and energy requirements of the state and assess the need for additional or
replacement generating facilities and the associated costs of such facilities to the electric
consumers of this state.
The legislation also requires that every public utility and generation and transmission
association or cooperative corporation, the Grand River Dam Authority, the Oklahoma
Municipal Power Authority, and any municipality proposing to construct generating facilities
shall submit to the Commission, for purpose of review, a list of all proposed projects for the
construction, alteration, or modification designed to increase electrical generating capacity
of any electricity-production facility located within the state along with any supporting data
the Commission might direct.
Although this report has been prepared by members of the Commission's Public
Utility Division Staff, neither the contents of the report nor the analysis methods used to
produce it constitute official Commission policy. However, the Staff, at its discretion, may
place any element of the report (including conclusions and recommendations) before the
Commission to request endorsement or other actions within the jurisdiction of the
5
Commission.
The purpose of this report is to review and summarize the electrical power and
energy requirements which existed in the State of Oklahoma for the years 2008 and 2009.
Furthermore, the report sets forth in total for the state, projections of maximum available
capacity, firm power purchases, peak energy demand, capacity margins, newly proposed
transmission lines and substations as well as upgrades to existing transmission lines and
substations, over the next ten years, i.e., from 2010 to 2019.
6
CHAPTER TWO
PROVIDER OVERVIEWS
This chapter presents a brief overview of the major energy Providers in the state and
the service territory of each. The discussions are arranged according to the relative
number of customers and sales of the Providers. The State's two largest investor owned
electric utilities, OG&E and PSO, are discussed first, since these companies have more
customers and sell more electric power in Oklahoma than any of the other Providers.
Discussed next is Empire District Electric, who is the smallest investor owned electric utility
operating in the state followed by Grand River Dam Authority, Oklahoma Municipal Power
Authority, and Western Farmers Electric Cooperative. The discussion then concludes with
KAMO Electric Cooperative.
The Providers listed in the previous paragraph serve both over-lapping and
distinctive groups of customers in Oklahoma. Private power companies such as OG&E
and PSO generally provide service to customers in non-rural areas of the state, e.g.,
Oklahoma City, Tulsa, Lawton, Muskogee, and Enid. Rural areas of the state are typically
served by Western Farmers Electric Cooperative (and the 19 distribution cooperatives
which govern Western Farmers) and KAMO Power (and the eight seventeen cooperatives
which sit on the KAMO governing board). The Grand River Dam Authority serves both
rural and non-rural areas of the state, while the Oklahoma Municipal Power Authority
provides power to municipalities that voluntarily become members of the Authority. Empire
District Electric Company serves a relatively small group of customers in both rural and
non-rural areas in the northeastern portion of the state. Empire District Electric serves
approximately 4,700 customers in Oklahoma; however, system-wide Empire serves
approximately 168,000 electric customers in a four state area, i.e., Arkansas, Kansas,
Missouri and Oklahoma. However, most of Empire's customers and their operations are
located in the state of Missouri.
7
Historical Overview
Oklahoma Gas and Electric Company
OG&E is an investor-owned public utility engaged primarily in the generation,
transmission, and distribution of electricity to retail and wholesale customers in Oklahoma
and Arkansas. OG&E is the largest electric utility in Oklahoma. In 1928, OG&E sold its
retail gas business and has since been a provider of only retail and wholesale electricity.
The OG&E electric generation system consists of nine interconnected fossil fuel generating
stations, most with multiple units and two wind farms located in western Oklahoma.
OG&E's headquarters are located in Oklahoma City.
OG&E serves more than 779,000 retail customers in Oklahoma and western
Arkansas, and a number of wholesale customers throughout the region. OG&E, with about
6,600 MW of generation capacity, generates electricity from natural gas, western coal, and
wind. OG&E's electric transmission and distribution systems span 30,000 square miles.
Enogex, OG&E's sister company, operates a pipeline system engaged in natural gas
gathering, processing, transportation, storage and marketing. The system includes about
8,200 miles of pipe, eight processing plants, and 24 billion cubic feet of storage capacity.
OGE Energy Corporation, also with headquarters in Oklahoma City, is the parent
company of Oklahoma Gas and Electric Company and Enogex. OGE Energy and its
subsidiaries have about 3,400 employees.
Oklahoma Gas & Electric Owned Generation Sources:
Plant Name Location Megawatt Capacity
1. Enid (gas) Garfield, OK 60MW
2. Horseshoe Lake (gas) Oklahoma City, OK 974 MW
3. McClain (gas) Newcastle, OK 363 MW*
4. Muskogee (coal) Muskogee, OK 1,889 MW
5. Mustang (gas) Oklahoma City, OK 613 MW
8
Luther, OK
Seminole, OK
Red Rock, Ok
Woodward, OK
601 MW*
1,724 MW
1,138 MW
1,1 MW
120 MW
101 MW
6. Red Bud (gas)
7. Seminole (gas)
8. Sooner (coal)
9. Woodward (gas)
10. Centennial (wind)
11. Sooner Spirit (wind)
*OG&E ownership capacity
For more information about OG&E refer to:
http://www.oge.com/investorrelations/Pages/lnvestorRelations.aspx
9
American Electric Power/Public Service Company of Oklahoma
PSO can trace its roots back to 1889, when the Vinita Electric Light, Ice and Power
Company was chartered in Indian Territory to provide electric service to that community.
PSO was incorporated May 29, 1913 in Oklahoma City, by consolidating that company with
electric companies and related businesses in Tulsa, Guthrie, Coalgate, Lehigh and Atoka.
PSO's founder and first president was Frederick William "Fred" Insull, who moved
PSO's headquarters to Tulsa in 1916. Insull was the nephew of Samuel Insull, a former
secretary to Thomas Edison, who later became one of the most prominent figures in the
electric utility industry.
PSO was a member of the Central and South West Corporation (CSW), an investor
owned public utility holding company. Effective June 15, 2000, CSW merged with
American Electric Power Company (AEP), a multi-state electric utility operating in 11 states.
The former CSW properties continue to operate and are identified as AEP West.
Until 1925 PSO operated in Oklahoma as part of Middle West Utilities. PSO
became part of Central and South West Utilities in 1925; and in 1947 Central and South
West Utilities became a public utility holding company. AEP West owns three other
companies aside from PSO. These three are Southwestern Electric Power Company,
Texas Central and Texas North. Southwestern Electric Power Company is an electric utility
operating in Texas, Louisiana, and Arkansas. The other two companies, Texas Central
and Texas North, are providers of electric transmission and distribution facilities for
unregulated electric utilities in the state of Texas. PSO's operations are entirely within
the State of Oklahoma. Among the Providers covered by this report, PSO is unique
because of its ownership by AEP and its relationship to the other three companies owned
by AEP West. AEP has adopted an integrated approach to long-range resource planning.
This means that PSO and the other utilities owned by AEP do long-range resource
planning in terms of the needs of the AEP system as a whole. PSO's corporate
headquarters are located in Tulsa, while AEP's corporate headquarters are located in
Columbus, Ohio.
10
American Electric Power is one of the largest electric utilities in the United States,
delivering electricity to more than 5 million customers in 11 states. AEP ranks among the
nation's largest generators of electricity, owning nearly 38,000 MW of generating capacity
in the U.S. AEP also owns the nation's largest electricity transmission system, a nearly
39,000-mile network that includes more 765-kilovolt extra-high voltage transmission lines
than all other U.S. transmission systems combined.
With approximately 4,400 MW of capacity and nearly 1,700 employees, PSO today
serves approximately 527,000 customers in 230 cities and towns across 30,000 square
miles of eastern and southwestern Oklahoma. The company's distribution operations are
organized into three districts: Tulsa, Lawton, and McAlester. PSO is headquartered in
Tulsa, with regulatory and external affairs offices in Oklahoma City, while AEP corporate is
located in Columbus, Ohio.
PSO Owned Generation Sources:
Plant Name Location Megawatt Capacity
1. Comanche Comanche, OK 294MW
2. Northeastern (coal & gas) Rogers, OK 1,593.5 MW
3. Oklaunion (coal) Vernon, TX 107 MW *
4. Riverside (gas) Tulsa, OK 948.7 MW
5. Southwestern Caddo, OK 485MW
6. Tulsa Tulsa, OK 443.2 MW
7. Weleetka Okfuskee, OK 163 MW
* PSO's power allocation of the total plant capacity based on ownership percentage.
For more information about AEP/PSO refer to: http://www.aep.com/
11
Public Service Company of Oklahoma Service Territory
12
AEP Generation Facilities
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13
Empire District Electric Company
Founded in October 1909 as a part of Cities Services Company, Empire District
Electric Company is an investor-owned public utility operating in Arkansas, Kansas,
Missouri, and Oklahoma; however, all but one of EDE's generation facilities and most of its
electric power sales are in Missouri. EDE operates seven generation plants, none of which
are located in Oklahoma. Most of Empire's generating facilities are located in southwestern
Missouri; However, Empire does have generation facilities located at Riverton, Kansas and
Plum Point, Arkansas EDE's Oklahoma customers (4,700) account for approximately 3.5%
of the total demand on the EDE system. EDE's Oklahoma electric power sales account for
about 0.2% of the total electric demand in the state of Oklahoma. EDE headquarters are
located in Joplin, Missouri.
Empire District Electric serves approximately 168,000 electric customers in
Arkansas, Kansas, Missouri and Oklahoma. Empire's Oklahoma operation is limited to the
far northeastern counties of Craig, Delaware and Ottawa.
Empire District also provides natural gas (through its wholly owned subsidiary, The
Empire District Gas Company), and water service, with approximately 217,000 total
customers in Missouri, Kansas, Oklahoma, and Arkansas. A subsidiary of the Company
also provides fiber optic services.
Empire District Electric Owned Generation Sources:
Plant Name Location Megawatt Capacity
1. Asbury (coal) Asbury, MO 207MW
2. Riverton (coal & gas) Riverton, KS 286MW
3. latan Unit 1 & 2 (coal) 12% Weston, MO 187 MW*
4. State Line (gas) 60% Joplin, MO 300 MW*
5. State Line Unit 1 (gas) Joplin, MO 96MW
6. Empire Energy Cntr (gas) LaRussell, MO 267MW
14
7. Ozark Beach (hydro) Ozark Beach, MO 16MW
8. Plum Point (coal) 7.52% Osceola, AR 50 MW*
*EDE's ownership capacity
For more information about Empire District Electric refer to: https:/Iwww.empiredistrict.com/
Empire District Electric in Oklahoma
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THE EMPIRE DISTRICT ELECTRIC COMPANY
ELECTRIC AND GAS SERVICE TERRITORIES
o GAS • POWER PLANT o ELECTRIC '* SERVICE CENTER
,-. .: ~,
Grand River Dam Authority
The Grand River Dam Authority is an Agency of the State of Oklahoma, organized
and existing pursuant to Title 82, Oklahoma Statutes, Sections 861 et seq. , one of only two
such entities that exist in the United States, which were established by governmental
action, the other being the Tennessee Valley Authority. GRDA was created by the
Oklahoma Legislature in 1935 as a conservation and reclamation district and it owns and
15
operates electric generation, transmission, and distribution facilities mainly within the
northeastern quadrant of the state. GRDA is governed by a seven member board of
directors comprised of three members appointed by the Governor, one designated by the
President Pro Tempore of the Senate, one designated by Speaker of the House of
Representatives, one designee of the Oklahoma Association of Electric Cooperatives, and
one designee of the Municipal Electric Systems of Oklahoma. GRDA is now a major
supplier of electricity not only in Oklahoma but regionally. GRDA headquarters are located
in Vinita, Oklahoma.
GRDA Owned Generation Sources:
Plant Name Location Megawatt Capacity
1. Pensacola (hydro) Langley, OK 126 MW
2. Markham Ferry (hydro) Locust Grove, OK 117 MW
3. Salina Pump Storage (hydro) Salina, OK 260MW
4. CFP 1 (coal) Chouteau, OK 490MW
5. CFP 2 (coal) 62% Chouteau, OK 322 MW*
6. Redbud (gas) 36% Luther, OK 443 MW*
*GRDA's ownership capacity
16
Grand River Dam Authority Map of Customers and Facilities
Alfalf, Kay .
Pawnee e ·~m_nc'0 Siloam
Springs
W.gon~ Tahlequah
o Stilwell o
1'1"'1' vf CuctvW(!U ,In{j GROA J!;«l!Itkl
"""~c,, ·~,,,~~uv..cI\""'~m'OlfMtBf+G) O+PI (I!+Q)
2008 1,031 3,349 0 25 0 4,405 0 254 0 0 27 44 0 0 325 4,730
AEPIPSO
2009 1,026 3,359 0 25 0 4,410 0 390 0 0 17 44 0 0 451 4,861
2008 380 854 16 0 0 1,250 162 0 0 0 7 0 0 0 169 1,419
Empire
2009 382 859 16 0 0 1,257 162 0 0 0 7 0 0 0 169 1,426
2008 812 0 500 0 0 1,312 0 228 0 0 0 13 0 0 241 1,553
GRDA
2009 812 430 503 0 0 1,745 0 78 0 0 0 13 0 0 91 1,836
2008 198 0 0 0 0 198 889 805 181 14 0 0 0 0 1,889 2,087
KAMO
2009 198 0 0 0 0 198 781 707 159 12 0 0 0 0 1,659 1,857
200B 2,595 3,517 0 0 4 6,116 0 0 0 0 50 0 0 490 490 6.606
OG&E
2009 2,542 4,058 0 0 4 6,604 0 0 0 0 50 0 0 490 490 7,094
2008 147 293 29 0 8 477 0 () 0 0 () () 259 0 259 736
OMPA
2009 147 439 29 0 8 623 0 0 0 0 0 0 193 0 193 816
2008 440 765 0 0 0 1,205 0 0 0 0 0 279 0 0 279 1,484
WFEC
2009 440 900 0 0 0 1,340 0 0 0 0 0 279 0 0 279 1,619
2008 5,603 8,778 545 25 12 14.963 1,051 1,287 181 14 84 336 259 490 3.638 18,601
Total
2009 5,547 10,045 548 25 12 16,177 943 1,175 159 12 74 336 193 490 3.320 19,497
Percent of 2008 30.12% 47.19% 2.93% 0.13% 0.06% 80.44% 5.65% 6.92~t 0.97% 0.08% 0.45% 1.81% 1.39% 2.63% 19.56% 100.00%
Total
Energy 2009 28.45% 51.52% 2.81% 0.13% 0.06% 82.97% 4.84~. 6.03'_ 0.82% O.OfW. 0.38% 1.72% 0.99~. 2.51% 17.03% 100.00%
Note: Based upon discussions with OG&E and OMPA. Staff believes that the companies used different SPP formulas (timing) to determine the available capacity for Renewable Power Gen.
(column "GOO). Staff believes that the total for both companies should be reported as 6 megawatts for both 2008 and 2009.
27
Total Energy Generation Capability
Table 3-2 Report
Existing Maximum Energy Generation Capability of Providers (megawatt hours)
A B C D E F G H
Total Provider
Ener'gy
Generation
Provider Year Coal tlatural 'Gas Hydro Oil R,enewables Capacity
(C+D+E+F+G)
2008 9,031,560 29,337,240 I) 219,000 o 38,587,800
,A,EPJPSO
2009 8,987,760 29,,4.24,B40 0 219,000 0 38,631,600
20008 3,328,800 7,481,040 140,160 ° 0 10,950,000
Empire
2009 3,346,320 7,524,840 140,160 0 0 11,011,320
20018 7,1~13,1120 9'70,1070 4,380,00:0 0 0 12.463,290
GRDA
2009 7.113,1i20 3,880,680 4,406,280 0 0 15,400,080
2008 1,734,000 0 0 0 0 1,734,000
KAMO
2009 1,734,000 0 0 0 0 1,734,000
2008 22,732,200 30,808,920 0 0 35,040 53,576.160
OG&E
2009 22,267,920 35,548,080 0 0 35,040 57,851,040
2008 1,291,000 2,574,000 255,000 0 70,000 4,190,000
OMPA
2009 1,288,000 3,846,000 254,000 0 70,000 5,458,000
2008 3,276,000 5,361,,000 0 0 0 8,637,000
WFEC
2009 3,276,000 6,307,000 0 I) 0 9,583,000
20008 48,506,680 76,532,370 4,775,160 219,000 105,040 130,138,250
TOTAL
2009 48,013,120 86,531,440 4,800,440 219,000 105,040 139,669,040
Per,oe:nt of 2MB 37.,21% 58.81%. 3.61% 0.17% D.oS%. 100.00%.
Tota.l
Energy l{J(}9 34.38%. 61.95%. 3.44% O.16'-~ O.OS%. 100.00%
Note: Based upon discussions with OG&E and OMPA. Staff believes that the companies used different SPP formulas (timing) to
determine the available capacity for Renewables (column "G"), Staff believes that the total for both companies should be reported
as approximately 52,000 megawatt hours for both 2008 and 2009.
28
Table 3-3, Report
Actual Peak Demand for the Providers (megawatts)
A B C D E F G Hi I J K L fill ~I 0
Total P,Qwer
Capacity Reserve
Peak System Actual Peak Adjusted ~GeneratiQn Res,elve Margin
Natural. Hydro Purchase P.eak Demand Side Peak and Reserve Mar'g,inWith llirithout
Prov.ider Year C.oalPeak Gas,P,eak Peak Oi\!Peak Renewables Power Demand Management Demand Purcilas'es) Margin Purchases Purchases
~q+ID~+IE)+ (I)+(J) ILHK) IM)!(K) UMHHW(K) (f)+(G)
20>0'8 499 2,487 0 () ao U34 4,201) 7 4,207 4,686 479 111.39% -15.57'%
AEPJPSO
20109 907 2,0117 0 0 73 9197 3,994 5 3,999 4,817 B118 20.46% -4.48%
2008 344 642 14 0 6 146 1,152 8 1,160 1,426 266 22.91% 10.33%
Empire
2009 344 575 14 0 6 146 1,085 8 1,093 1,426 333 30.44% 17.09%
2008 71iO 0 317 0 0 1150 1,171 10 1.1,87 11,553 366 30.8:3% 18..20%
GRDA
2009 7.25 400 274 I} I) 0 1,,3919 10 11,409 1,758 349 24..77% 24.77%
2008 198 0 .0 o 0 1672 1,,870 .0 1,870 2,087 217 11.60% 11.60%
KAMO 20,09 198 0 0 ° 0 1445 1,643 00 1,643 1.857 214 13.0,2% 13.02%
2008 2,358 2,772 0 I} 54 383 5,567 0 5,567 6,485 9118 16.49% 9.61%
OG&E
2009 2,378 3,122 0 0 115 443 5,958 0 5,958 6,876 918 15.41% 7.97%
2008 125 212 5 n 0 316 668 0 658 736 78 11.8,5% -36.17%
OMPA
2009 108 340 30 0 2 1917 671 0 677 816 139 20.53% -8.57%
2008 429 4910 256 0 44 257 1,476 0 1,476 1,484 8 0.54% -16.87%
WFEC
2009 402 6,04 219 0 25 1194 1,444 0 1.444 1.619 175 12.12% -1.32%
2008 5,429 7,.408 679 14 184 2,386 16,100 25 16,125 18,457 2,332 14.46% -0.34%
Total
2009 5,711 7,765 613 13 121 1,,977 16,200 23 16,223 19,169 2,946 18.16% 5.97%
29
Table 3-4
Actual Energy Available from the Providers tmegawatt hours)
-
A B C D E F G H I
Annual Annual
Purchased Provider
Provider Y,ear Coo'li Natural Gas Hydro Oil Renewabres Energy Energy
IC+I)fE+
F+G+H)
.2008 6,998,000 73760:00 0 0 1,322,000 5,035,000 21,231,000
AEPiPSO ' ,
2009 1,224,000 6,144,000 0 0 1,4.20,000 5,083,000 .20,411,000
200B 2,116,314 1,11.9,,814 32,601 339 593,544 1,631,041 5,493,553
Empire
2009 2,126,,950 143,,831 16,133 139 79'0;035 1,:525,518 5,263,206
.2008 5,612,618: 239,013 1,421,325 I) 0 343,244 1,622,260
GRDA
2009 5,493,609 1,3.22,444 1,283,516 0 I) 128,920 8,223,549
2008 14211249 0 '0 0 0 8663383 10,084,632
KAMO ' , , ,
2009 1I,346,R26 (} '0 0 '0 1,260,568 8,601,394
2008 11,511,480 1,621,618 I) 0 604,880 2,618,530 28,482,508
OG&E
2009 15,063,228 9,431,266 ° I) 548,195 2,313,8,30 21,356,519
.2008 953;000 608000 184,000 '0 112;000 881,000 2,198~000
OMPA
,
.2009 692,:000 11,.51000 150,000 '0 153;000 196,000 2,942,000 I: t
2008 3,161,660 1,482,914 1,045,000 I) 1,665,689 215,000 1,636,263
WFEC
2009 3101588 1,501,654 905,934 0 1,468,635 530,683 1,514,494 Jl' , ,
2008 31840321 1:B,953,419 .2,68B,9.26 339 4,;358,11'3 19,501,198 83,348,316
TOTAL ' ,
2009 35,'048,2011 20,.900"t95 2,41,6,243 139 4,319,865 111,638,519 17,441',162
30
Generation System Capability
The generation capability of an electrical generation system is defined as the total
net megawatt generation capacity of the units operating on the system. The watt is the unit
of measurement used to quantify the power generating capacity of electrical generators. A
kilowatt (kW) is 1,000 watts, while a megawatt (MW) is one million (1,000,000) watts. This
means that the measurement of the kilowatts or megawatts available from an electrical
generation system tells us how much power is available from that system. Typically,
electrical generation systems are designed so that the power output of the system meets,
or exceeds, the maximum demand for power expected to be placed on the system.
Electric bills to customers can be based on either kilowatts or kilowatt hours (kWh)
or both. Most bills to residential and commercial customers have charges computed in
terms of kilowatt hour usage, while bills to some larger commercial customers and most
industrial customers have charges computed in terms of both kilowatt hours and kilowatts.
The kilowatt hour portion of an electrical bill usually is referred to as billing for "energy
usage," while the kilowatt portion of such a bill usually is referred to as billing for "demand
on the generation system." The energy charge is based on the total kilowatt-hours used.
Kilowatt-hours are the unit of electricity measured by the electric meter. For example, a 100
watt light bulb burning for 10 hours would be 1,000 watt-hours or 1 kWh (100 watts X 10
hours = 1000 watt-hours).
This billing division has been described in terms of a commodity charge (kilowatt
hours) for energy used, and a capacity reservation charge (kilowatts) for construction and
ownership of the generation units themselves, as well as transmission and distribution
facilities. However, this portrayal of the billing division is incorrect in one very important
respect. In fact, the bills of all customers include payment to cover both the cost to build
and own the generation, transmission, and distribution systems, as well as the costs
associated with actually using those systems to generate electricity. The bills of some
commercial customers and most industrial customers show this division explicitly, while the
two types of cost are aggregated in bills delivered to residential customers and most
commercial customers.
31
There is wide variation in the power and energy production capability of the
Providers' generation systems. OG&E is the largest Provider in the state in terms of
generation capacity and energy generation capability, followed by AEP/PSO. GRDA and
WFEC essentially are identical in terms of their generation capacity and energy generation
capability, with OMPA coming fifth in these categories. Empire District neither owns nor
operates a generation plant within Oklahoma. Empire District's generation facilities are
located in the states of Missouri, Kansas and Arkansas. Empire District is the smallest
investor owned electric utility operating in Oklahoma with approximately 4,700 customers
located in northeastern Oklahoma. KAMO owns approximately 38% of GRDA's No.2 coal-fired
generation facility located in Chouteau, OK. Associated Electric Cooperative, Inc. has
integrated KAMO's portion of this unit into its generation resources. AECI provides
approximately 99% of KAMO's power needs. The remainder of the power is purchased
from small suppliers.
Generation System Reliability
The reliability of a generation system is an expression of the capability of the system
to successfully meet the maximum demand likely to be placed on the system during some
specified time interval. The expected reliability of a system of generation units can be
measured in one of several ways. First, one can compute the actual and forecasted
reserve and capacity margins for the system. Both reserve margin and capacity margin are
ratios. The reserve margin for a generation system is the difference between peak system
generation capacity and actual peak demand on the system during a year divided by the
actual peak demand on the system, expressed as a percent. Capacity margin is this same
difference divided by the peak system generation capacity of the system. These
computations can be made using either actual or forecasted values for peak system
generation capacity and peak system demand.
Loss of load probability (LOLP) is another way to measure the expected reliability of
a generation system. LOLP is computed based on forecasts of peak generation system
capacity and peak system demand. LOLP is the computed probability that the system will
32
be unable to serve the maximum (peak) demand placed on it over some specified planning
horizon. LOLP is expressed in terms of the number of days during the planning horizon
when the system will be unable to meet the peak demand placed on it. A well-designed
and managed generation system is likely to have a LOLP of one day in 10 years. This
formula says the system is expected to be unable to meet the maximum demand placed on
it only one day every 10 years. Many power production planning computer models
compute a reliability measure very similar to the LOLP. These models compute the
expected loss of load hours during each year of the planning horizon.
In terms of the reliability criteria described above, not all of the Provider's generation
systems are "reliable" on a stand-alone basis to the point that system capability has
sufficient reserve; however, when Provider generation capacity and purchased power are
combined, (See Table 3-3 Column N) the reserve margins are significantly improved. For
2008, the highest reserve margin among the Providers operating generation facilities in
Oklahoma was GRDAs 30.83%, while the lowest was WFEC's 0.54%. For 2009, the range
was from Empire District's 30.44% to WFEC's 12.12%, including purchased power. The
generation systems of the other Providers fall somewhere between these extremes. For
the state as a whole, the reserve margins for 2008 and 2009 are 14.46%, and 18.16%,
respectively, when purchased power is included. When only Provider generation capacity
is considered, the range for 2008 is from GRDA's 18.20% to OMPA's negative 36.17%,
while the range for 2009 was from GRDA's 24.77% to OMPA's negative 8.57%. Based
only on Provider generation capacity, the statewide reserve margins for 2008 and 2009
were a negative 0.34%, and a positive 5.97%, respectively. The reserve margin for 2008
and 2009 indicates there was insufficient generation capability to meet statewide peak
demand without purchasing power or demand reduction programs.
Generation System Efficiency
Measurement of the efficiency of a generation system is an assessment of the
relative amount of input resources and monetary cost required by the system to generate
each unit of electrical energy (kilowatt hour) coming from the system. We shall refer to the
first type of efficiency as resource efficiency. The most widely used measure of resource
33
efficiency is the system heat rate. The system heat rate is defined as the number of British
thermal units (Btu) required by the system to generate a kilowatt hour of electrical energy
during some specified time interval. The system heat rate can be computed as an average
for the system over a period of time, such as a year, or as the incremental heat rate for the
system. The system incremental heat rate is the number of Btu required to generate the
next kilowatt hour produced by the system. A system's heat rate may be calculated by
dividing the system's Btu output by the quantity of kilowatt hours produced by the system
(Heat Rate = (Btu + kWh).
Both the system average and system incremental heat rate can be used as
measures of actual system performance over a historical period of time, for example over a
year's time. However, both system heat rates can also be forecasted by power production
planning computer models. In assessing the future efficiency of the system, the
incremental system heat rate is a more useful forecasted value. However, it also is more
difficult to forecast, since it is based not only on expected system operations but also on
past tests of the system's generation efficiency at various load levels. When interpreting
system heat rates, the system is more efficient as the heat rate drops.
The second criterion used to assess the efficiency of a generation system is the
cost per kilowatt hour produced by the system. Like the system heat rate, the cost per
kilowatt hour produced also can be computed either as an average or as the cost to
produce the next kilowatt hour from the system (incrementally). Unlike the system heat
rate, however, the cost per kilowatt hour produced is an economic rather than a physical
measurement of the system's efficiency. This difference is of little significance when the
historical average cost per kilowatt hour produced is computed, since this value is
computed using measurements of past cost and kilowatt hour generation.
This difference is more important in the case of forecasts of cost per kilowatt hour
produced, since forecasting the cost of such variables as cost of fuel, maintenance cost,
and operational cost is speculative when compared to forecasts of the heat content of fuels
or the mechanical efficiency of the generation units operating on the system.
Table 3-10 for each of the Providers contains the system average heat rate for each
Provider's generation system, for the years 2008 and 2009. For 2008, these heat rates
34
ranged from 6.549 to 10.91 Btu/kWh. KAMO's system had the highest (or least efficient)
heat rate for 2008 at 10.91, while GRDA's system had the lowest (or most efficient) heat
rate for 2008 at 6.549. KAMO's system also had the highest heat rate, at 11.07 for 2009,
while GRDA's system had the lowest heat rate, 7.027 for 2009.
Many factors can impact the efficiency of a generation system. Several of these
factors relate to the generation units in operation on the system. Among these factors are
the technology bases of the generation units, the age of the generation units, the manner in
which the units are operated, and the maintenance performed on the units. If generation
system efficiency is measured in terms of the kilowatt hours delivered to the consumer,
other factors may affect the efficiency of the system as a whole. Among these are the
design and operation of the transmission system delivering power from generation units to
the distribution system, the design and operation of the physical interconnections which tie
the generation units, transmission system, and distribution system together, and the design
and operation of the distribution system which actually delivers electrical energy to
consumers.
Generation Fuels
This discussion is limited to a review of the fuels used by the Providers' generation
systems during 2008 and 2009.
Nearly all generation units operated by the Providers are fired by fossil fuels. The
exceptions are the hydroelectric facilities operated by Empire District Electric in Missouri
and the hydroelectric operations in Oklahoma owned by GRDA and OMPA, and the wind
generation owned by OG&E in western Oklahoma. There are other non-fossil fuel
generation facilities located in the state. These facilities include the hydro plants operated
by the Southwestern Power Authority and various wind generation facilities located
predominately in the western portions of the state. These non-fossil fuel facilities generally
provide purchase power to most if not all of the Providers.
Table 3-1 indicates in 2008 and 2009 there were 5,603 and 5,547 MW, respectively,
of coal-fired generation capacity owned by the Providers who operate in the State of
35
Oklahoma. Table 3-1 shows that in 2008 there were 8,778 MW of natural gas-fired
generation capacity, which increased significantly in 2009 to 10,045 MW. Oil-fired
generation was 25 MW for both years, while hydro generation capacity for the same period
was 545 MW in 2008 and 548 MW in 2009. Renewable capacity, which was primarily wind,
was 12 MW for both years.
Table 3-4 shows the actual electrical energy available to the Providers during 2008
and 2009 by fuel type. These values represent the actual energy produced in terms of
megawatt hours, where the values in Table 3-1, discussed in the preceding paragraph
represent the capacity of the Providers generation facilities in megawatts. Coal-fired
generation was 37,840,321 MWH for 2008, and 35,048,201 MWH for 2009, while natural
gas-fired generation was 19,953,419 MWH for 2008, and 20,900,155 MWH for 2009.
Hydro generation was 2,688,926 MWH for 2008, and decreased to 2,416,243 MWH for
2009, which was still a significant increase from the previous report. Once again, GRDA's
hydro energy accounted for the majority of all hydro production. Empire District accounted
for nearly all oil generation which was 339 MWH for 2008 and, only 139 MWH in 2009.
Electric generation by renewable sources (predominately wind) for 2008 was 4,358,113
MWH, and 2009 was 4,379,865 MWH. Renewable energy generation increased
significantly for most companies over the two-year period primarily due to the abundance of
wind in Oklahoma. With the addition of needed transmission facilities, wind energy should
continue to play a significant role in Oklahoma's future energy picture. In 2010 the
Oklahoma Legislature past two bills related to wind energy, i.e., HB 3028 and HB 2973.
HB 3028 established a renewable energy standard of 15% for the state, which meant that
15% of the state's generation in 2015 would be from renewable energy sources. HB-2973
set a standard for the decommissioning of wind turbines and wind farms.
System Fuel Use and Cost
Table 3-5 below, presents information on the total fuel burned by the Providers in
2008 and 2009 to produce electrical energy. Fuel use for 2008 varies from 259,988,755
MMBtu used by OG&E to 13,884,769 MMBtu used by OMPA. For 2009, the range is from
36
247,463,096 MMBtu burned by OG&E to 13,793,236 OMPA. Fuel cost data is presented in
two forms in Table 3-5, i.e., cost per million British thermal units ($/MMBtu) and cost per
megawatt hour ($/MWh). The first is a measurement of the average cost per heat unit of
the fuel itself; while, the second is the average fuel cost related to each MWh generated.
The second is the portion of the per MWh cost of electricity generation which is attributable
to the cost of the fuel used to generate an average MWh from fossil fuel burning plants.
The average cost of fuel for the Providers listed in Table 3-5 is $3.62/MMBtu for 2008 and
$2.57/MMBtu for 2009. The average cost per Mwh generated was $34.99 in 2008 and
$24.63 in 2009.
Table 3·5
System Fuel Use and Cost for the Providers (mec awatt hours}
A B C D E F G
Average
Average
Total Annual Quantity of
Total Fuel Fuel Cost
Energy
Provider Year Generation Fuel Burned Cost ($) ($IMMBtu) Cost- Fuel
(MWH) (MMBtu) (Ell(D) ($1MWH)
(E)/tC)
.200B 14,872,057 1149,575,114 $722,639,130 $.4.83 $48.59
AEPiPSO
21)09 13,9166,152 1141.,056,236 $.370,769,277 $2.63 $26.55
.200H 3,236,467 31,770,105 $100,005,446 $.3.15 $.30.90
Empire .200.9 2,8.70,920 29,684,28.7 $.94,430,.829 $.3.18 $32.8.9
2008 7,270,874 47,613,455 $98,340,950 $2 ..07 $13 ..53
GRDA .2009 8,055,B28 56,604,665 $1130,956,467 $2.31 $1626
.2008 1,421,249 15,503,074 $22,764,000 $1.47 $.16.02
KAMO
2009 1,346,826 14,912,789' $22,920,000 $.1.54 $17.02
2008 25,6,96,fil.37 259,988,755 $865,725,.266 $3.33 $33.69
OG&E
20n9 25,008,476 247,463,096 $624,859,240 $2.53 $24.99
2008 1,561,000 13,884,769 $52,43.5,836 $.3.78 $33.59
OMPA
2009 1,844,000. 13,793,236 $42,277,148 $3.07 $.22.93
2008 4,650,000 49,810,298 $1192,452,381 $3.86 $41.39
WFEC
2009 4,608,000 49,437,611 $1'35,136,009 $.2.73 $29.33
.2008 58.,708,484 568,145,570 $2,054,363,00.9 $.3.6.2 $34.99
TOTAL
.2009 57,700,202 552,951,9'20 $1,421,348,970 $2.57 $24.63
37
Electric System Cost
Table 3-6 summarizes cost data taken from Table 3-10 presented below. The costs
in Table 3-6 are those involved with both owning and operating the Providers' generation
systems, as reported by the Providers. These costs are divided into five categories.
Columns (D) and (E) include the cost to purchase off-system power and the cost incurred
to actually operate the generation system producing electrical power. Columns (F), (G),
(H), and (I) present the costs associated with constructing and owning the electrical
generation systems. The final column of Table 3-6 presents the average cost per
megawatt hour to generate power on each Provider's system. The final row in Table 3-6 is
labeled "total." This row presents the total cost for each column, as well as the average
cost per megawatt hour for all the Providers together. The average cost of generation for
the Providers was $65.34/MWh in 2008 and $57.1 O/MWh in 2009. The megawatt hour cost
of generation for the individual Providers varies considerably. For 2008, the range was
from KAMO's $35.27/MWh to Empire District's $89.41/MWh. The range for 2009 was from
KAMO's $36.07/MWh to Empire District's $92.92/MWh.
Table 3-6
System Costs for the Providers
A B C D E f G H I J K
Fuel and Operations &
Annual MWH of Purchase Maintenance Depreciation Average Cost
Provider Year Energy Sales Power Cost Cost Cost Debt Cost Taxes Net Income Total Revenue perMWH
(D)f-(E)+(f)+(G)+(
Hlf-!I) 1000"(J)!(C)
2008 19,839,000 S1,052,519 S248,018 $1.05,249 $75,088 SO :578,484 $1,559,358 $78.60
AEP/PSO
2009 19,207,000 :5570,155 $293,595 $110,149 $57,306 $0 $75,602 $1,106,807 $57.63
2008 5,116,502 $182,518 $93,209 $50,019 $28,793 $63,189 :539,722 :5457,449 $89.41
Empire
2009 4,893,941 $170,311 $86,145 :547,746 S32,343 $76,938 :541,296 :5454,780 $92.93
2008 7,047,353 $128,680 1544,172 $32,645 $37,722 $0 $82,969 $326,188 $4629
GRDA
2009 7,728,133 $138,546 $56,467 $48,596 $52,779 $0 $20,478 $316,866 :541.00
2008 10,084,632 $184,427 $124,626 $24,829 $0 $0 $21,826 $355,708 $3527
KAMO
2009 8,607,394 $145,029 $126,596 $26,313 $0 SO $12,545 $310,483 $36.07
2008 28,162,429 $1,122,730 $423,602 $145,533 $81,589 $0 $143,007 $1,916,461 $68.05
OG&E
2009 26,880,647 $801.41'8 $442,514 $166,245 $96,106 $0 $200,440 $1,706,723 $63.49
2008 2,223,000 :596,524 $8,861 $11,544 $25,633 $0 -$231 $142,331 $64.03
OMPA
2009 2,203,000 $68,228 $11,907 S15,111 $29,075 $0 -$1,779 $122,542 $55.63
2008 7,463,000 $321,311 $69,501 $20,643 :532,994 $0 $21,111 :5465,560 $62.38
WFEC
2009 7,2.86,000 :5224,132 $73,547 $22,969 $32,617 $0 $'13,841 $367,106 $50.39
2008 79,935,916 $3,088,709 $1,011,989 $390,462 $281,819 $63,189 $386,888 $5,223,055 $65.34
TOTAL
2009 76,806,115 $2,117,819 $1,090,771 5437,129 $300,226 $76,938 $362,423 $4,385,307 $57.10
Note: For OG&E this value is funds available for payments to both preferred and common shareowners.
38
Power Purchases
Table 3-1 shows that several of the Providers purchase power from outside their
generation systems. These purchases are divided into two primary categories. The first
category includes purchases from the Southwestern Power Administration (SWPA), a
federal agency that markets power generated by federal hydroelectric projects, located in
Oklahoma (operated by the Corps of Engineers.) The second category includes purchases
from non-utility power producers, both those certified by the Federal Energy Regulatory
Commission (FERC) as "Qualifying Facilities" (QF) under PURPA and other non-utility
power producers.
Table 3-7 shows the total energy in megawatt hours that the Providers purchased
during the years 2008 and 2009. It also shows the total costs of purchasing this energy.
Table 3-1
Purch,as,ed Power Quantity and Cost fa,r the Providers
A B C D IE
Purc!has.ed
Average Purc!has,ed
Provider Year Einergy Quantity
Purclhas,ed 8nergy 18ner1gy!Cost
(M1IIl11l1~
Cost ($)
($JM1IIlH)
(D)/(C)
2008 6.357,096 $329,879.997 $51 ..89
AEPIPSO
2009 6,502,504 $199,3816,178 $30.66
200B 2,224,5B5 $B2,5112,734 $.37.09
Empire
2009 2,31.5,55.3 $7.5,880,,646 $32.77
20081 343.244 $30,339.495 $818.39
GRDA
2009 1281,920 $7,589,678 $581.87
200B B,663,.383 $161,662,911: ,$1B.6,6
KAMO
2009 7,26,O,.56B $1122,,109,,077 $16.82
20081 4,364,90.5 $257 ,00.5,065 $581.13:8
OG&E
20091 3,837,&35 $176,55&,755 $46.UO
200B 8B1,OO.3 $44,08B.164 $50.04
OMPA
2009 795,6'06 $25,950,B52 $32.62
2008 .2,9881,000 $128,8481,67.2 $43.12
WFEC
2009 2,905,[1100 $881,8:96,002 $30.60
2008 25,822,216 $1,,034,337,038 $40.06
TOTAL
2009 23,745,986 $696,371,18B $29.33
39
Table 3-8
Firm Capacity and Reserves Purchases and Cost for the Providers
A B C D E
Purchased Capacity Av,erage Capacity
ProvIder Year Res'erv,es Capaci,ty Res'erve Reserve Cost
(MW) Cost ($) I$JMW)
(D)1(C)
2008 325 $5,609,000 $17,258
AEPiPSO
2009 451 $13,401,000 $29,714
2008 162 $16,193,520 $99,,9600
Empire
2009 162 $16,193,520 $99,9&0
2008 228 $10,308,221 $45,211
GRDA 2009 78 $3,519,826 $45,126
KAMO 22000089 223355 NN//AA NN//AA
2008 740 $93,879,037 $126,864
OG&E
2009 440 $83,149,933 518'8,977
20008 103 $8,847,,000 $85,893 OMPA 2009 101 $7,50.6,000. $74,317
2008 91 $5,715,000 $62,802
WIFEC
2009 91 $4,771,000 $52,429
2(1)008 1",649 $1:40,5511,,778 $85,235 TOTAL 2009 11,323 $128,541!,279 $97,159
Most of the electricity Providers have firm contracts in place to purchase up to a
fixed amount of energy from outside parties. Table 3-8 illustrates the total capacity that
each Provider had available under contract in the years 2008 and 2009. The table also
shows the capacity reserve costs associated with these contracts.
Demand-Side Management Programs
Almost all the Providers operate or have plans to operate some type of demand-side
management (DSM) programs. Of the major Oklahoma Providers in Table 3-9, only KAMO
and OMPA currently do not operate DSM programs.
40
Table 3-9 summarizes the potential and actual savings from DSM programs
currently operating on the Providers' systems. This table divides DSM programs into two
types. The first type consists of DSM programs designed to control or manage peak
demand. The second type includes DSM programs designed to promote energy
conservation by customers on the Providers' systems. Savings from the first type of DSM
programs are measured in terms of the megawatts of capacity additions the Providers were
able to defer or cancel because of these programs and the cost associated with these
capacity additions. Savings from the second type of DSM programs are measured in
megawatt hours of energy not generated by the Providers, and the costs associated with
that generation, which are directly attributable to the operation of the energy conservation
programs.
Table 3-9 Report
DSMProgram Potential & Actual Savings (megawatts & megawatt hours) for the Providers
A B C D E f
Peak Demand Ener'9Y Actual Peak
Actual Ener'9Y
Provider Year Management Conservati on Dem.and
Potentiaj 'MWH) Potential IMWH) Management (Mllll)
'Cans,ervation (MWH)
2008: 211 2,344 7 2,344
AEPJPSO
2009 33 20,300 5 20,300
2008 9 6,889 B 5,194
Empire
2009 10 9,525 B 7,923
2008 15 0 10 0
GRDA
20019 15 0 10 01
2008 0 0 0 0
KAMO
2009 0 a. 0 a.
2008 1133 0 46 6.446
OG&E
2009 145 0 193 46,5.23
2008 0 0 0' 0
OMPA
2009 0 0 a. 0
200.8 65 0 50 0
WFEC
20.09 65 0 50 0
200H 243 9,233 121 113,984
TOTAL
2009 268 29,825 26·6 74,746
41
Generation System Operations by the
Providers
Table 3-10
Annual System Operations Data for the Providers
A B C 0 E F G H I J K L M II 0
Actual Total Total System Total Lowest
Ilet System Actual System Average System Production System Resel"\re
Ilet Energy System Peak System System Production Cost-fuel & Capital Per Unit Margin
System Generation Energy Power Capacity Average Cost lIon- Purchas,ed Recovery Total System Cost for Du~ingthe Customer
Provider Year Capabinty Capability Generation Demand Factor Heat Rate Fuel Pow.er Cost Revenues Generation Year Meters
(MW) (MWH) IMWH! (MW) (%) (MBtul SO SO SO ($JMWH) (%)
KWH!
2008 4,405 38,587,800 14,875,057 4,200 39.57% 10.057 5248,018 $1,052,519 $258,821 $1,643,042 S105 13.90% 574.269
AEPIPSO
2009 4,410 38,631,600 13,966,152 3,994 36.51% 10.100 $293,595 $570,155 $243,057 $1,120,475 $79 23.30% 577,759
2008 1,419 12,264,000 3,862,612 1,152 36.10% 9.816 $27,856 5182,518 5118,534 $409,794 $89 22.91% 217,410
Empire
2009 1,426 13,245,120 3,737,688 1,085 32.20% 10.340 516,672 $170,311 $121,385 $411,975 $93 30.44% 217,254
2008 1,553 12,463,290 7,270,874 1,177 58.34% 6.549 $64,358 $128,680 $153,336 $323,747 $49 30.83% 130,216
GRDA
2009 1,836 15,400,080 8,055,828 1,399 52.31% 7.027 576,212 $138,546 $121,853 5317,669 S44 24.77% 132,249
2008 2,087 18,283,465 10,084,632 1,870 55.00% 10.908 $124,626 $184,427 $46,656 $355,708 $33 11.00% 326,283
KAMO
2009 1,857 16,268,969 8,607,394 1,643 53.00% 11.073 $126,596 $145,029 $38,857 $310,482 $33 13.00% 326,087
2008 6,606 57,868,560 32,058,870 5,567 55.40% 10.118 $187,058 $1,122,730 $370,129 52,036,214 $68 18.64% 702,378
OG&E
2009 7,094 62,143,440 30,254,293 5,958 48.68% 9.895 $1991,907 $801,418 $462,791 51,841,268 563 19.07% 709,081
736 4,189,968 1,916,712 658 45.75% 8.895 $8,861 $96,524 $36,946 $151,053 $64 11.85% Not
2008 Provided
OMPA
Not
2009 816 5,457,480 2,146,584 677 39.33% 7.482 $11,907 $68,228 $42,407 $147,670 $56 20.53%
Provided
2008 1,205 8,637,000 4,650 1,476 53.84% 10.712 $24,361 $321,311 $74,749 $43,821 $47 0.54% 269,593
WFEC
2009 1,340 9,583,000 4,608 1,444 48.19% 10.728 $27,191 $224,132 $68,427 $341,298 $35 12.57% 272,871
42
CHAPTER FOUR
PROVIDER PROJECTIONS AND FORECASTING METHODS
This chapter presents the forecast projections and forecasting methods as stated by
each of the seven Providers for the years 2010 through 2019.
Table 4-1 reflects a statewide estimate of the capacity margin for the Providers from
2010 through the year 2019. The table shows the relationship of the state's electric service
Providers' projected annual generation capacity to their projected annual demand.
Allowing for a cushion of 12 percent reserve margin as prescribed by the Southwest Power
Pool, the capacity in excess of 12 percent varies considerably for the projected period.
All Providers have supplied data for their existing and proposed transmission
facilities as well as any new and/or upgraded substations. Not only is there a need for new
transmission facilities and substations, many transmission lines and substations will need
upgrading in order to serve Oklahoma's growing electrical power consumption, especially
those related to new wind energy resources.
The Providers' forecasting techniques and methodologies range from econometric
forecasting to end-use modeling as performed by OG&E and AEP/PSO. Chapter Four
describes each provider's forecasting techniques and methods.
43
Projections for the Next 10 Years (2010 through 2019}
Table 4-1 reflects a statewide estimate of the capacity margin of the state's electric
Providers annually for the years 2010 through 2019. The table shows the relationship of the
state's electric service Providers' projected annual generation capacity to the Providers'
projected annual demand. The Southwest Power Pool prescribes a cushion of 12 percent
capacity margin. Capacity in excess of this 12 percent varies considerably for the projected
period. Providers seem to be relying more heavily on wholesale purchased power than on
new construction in generation facilities or purchase of existing generation facilities; however,
both OG&E and AEP/PSO have made additions to their systems, generally limited to
generation by natural gas powered facilities. Additionally, the Providers anticipate an
increase in peak demand from 16,196 MW in 2010 to 18,228 MW in 2019 for a growth rate of
12.55 compared to the projected growth rate of 15.3% found in the 2008 Electric System
Planning Report. The Providers anticipate a growth rate of only 3.62% for the maximum
available capacity generation for the years 2010 through 2019 compared to the ten year
projection of 19.43% in the previous report.
44
Table 4-1
Projeetions Of Maximum AUow,able Demand ForYe,ars, 2010 Thru201'9 by Providers (megawatts)
A B C D E f G HI I J K L M
Maxi:m,um,
Avail'able firm, P.eak Demand ~l,et Requi.r,ed Required CB!paci;." in
Y,ear Ca:paci,ty Capacity ToOtall Demand Side S},st,em CB!paci,ty Capacity Capacity Capacity exces.s of
(Generation) p.urchases Capa;ci,ty( Forecast ProOgrams Demand Mar'gin Margin Mar,gin Mar,gin 12%
(MViJ') (L\Ollil) MW) (MW) (PJ.lW) (MVi/) (••OW) (%) (MW) t%,) (MW)
(C+D) (f-'G) (E-H) (II E) (H~.38)-H II-K)
lio~all 2010 10,.327 2,98;8 19,315 1!o',1916 276 15,920 3,395 17.60% 2,1711 12.00cJ6, 1.224
Total 2011 15,443 2,89'8 19',341 15,480 334 15,146 3,195 15.50% 2,202 12.0'0% 9'94
liotal 2012 16,462 3,325 19',787 116,595 4913 16,1012 .3,685 118.,60% 2,196 12.00% 1,48:9
Total 2013 15,480 3,38.5 19',865 16,869' 613 15,256 3,510 18.20% 2,217 1.2.00% 1,393
1I01al 2014- 16,432 3,430 1,9,863 17,090 755 16,335 3,528 17.80% .2,227 12J)Or% 1,301
Total 2.015 15,537 3,340 19',877 17,285 825 16,459 3,418 17.20% 2,244 12.00% 1,174
li01al 20116 16,537 3,337' 119,874 117,508 862 16,646 3,228 16.20% 2,270 12.00% 958
Total 2017 15,795 3,39'0 20,185 17,755 879 16,877 3,309 16.40% 2,301 12.00% 1,0.0.8
liotal 20118 16,91191 3,396 20,31.5 17,986 8:99 17,0187 3,228 115.90% 2.330 112.00% 898
Total 20.19 16,9191 3,39'9' 20,319 18,228 9'04 17,324 2,994 14.70.% 2,362 12.00.% 632
REGIONAL BULK POWER TRANSMISSION FACILITIES
This section provides data on the statewide existing and proposed transmission facilities and substation upgrades.
Electric transmission lines carry electric energy from generating facilities to local communities. A distribution substation
reduces this high-voltage energy and transfers it to lower-voltage distribution lines, which carry the energy to individual
houses and businesses. In Oklahoma, transmission lines range in size from 69 kilovolts (kV) to 345 or 765 kV. Many
existing transmission lines will need upgrading over the next decade. Many new transmission lines and substations will
45
also be needed to serve Oklahoma's growing electricity use.
T ansmission LineCosts Forecast 2010 - 2019
350
• I I. - - • •
.AEPjPSO
• EMPIRE
.GRDA
KAMO
.OG&E
.OMPA
.WFEC
300
250
200
lime Cost ($M)
ISO
100
50
o
2010 2011 2012 2013 2014 2015 2015 2017 2018 2019
All the Providers, with the exception Empire District (which has planned no new transmission investment in
Oklahoma for years 2010 through 2019), have given investment estimates of their proposed and existing transmission
lines. (See page 34)
When more transmission capacity or service is needed in an area, two options are available to the Providers these
options are: 1) to upgrade existing transmission lines whenever possible, rather than to build new transmission
46
lines, and 2) to build new electric transmission lines where existing lines are not located.
The alternative to the first goal is to acquire many miles of new right-of-way in new
locations.
Transmission line owners will need to make major upgrades to the electric
transmission line system over the next decade. This is due to a number of factors, including
the age of existing facilities, increased electricity use by a growing Oklahoma population,
and the change in national regulation of utilities.
Power-line lengths are important in the transmission network. Although cost
estimates, service dates and line lengths are subject to change, OG&E proposes significant
transmission line additions in each of the next five years with major additions
(approximately $322 Million) occurring in 2012. AEP/PSO proposes major transmission
additions in 2013 and 2014 at a projected cost of $150 million. WFEC plans to invest
approximately $42 million in transmission facilities during 2010 and 2011, and KAMO plans
to invest approximately $75 million in transmission facilities during the next four years.
GRDA plans to make a $10 million investment in new transmission facilities during 2010.
47
LimeMiles 150
Transmlission Lines Forecast 2010 - 2019
300 -
I
!
I
!
•
J
-!..-
I
I
_I
I
I J
I I. I I
J I
I
I
I
J
- - • • ..,
.AEPjPSO
• fer""P'IRfe
.GRDA
KAIMO
.OG&IE
.OIMPA
.'uVFEC
250
200
10;0
50
o
2010 2011 2012 2013 2014 20]LS 2016 2017 2018 20]['9
48
$50.00
$45.00
$40.00
~ $35.00
~
-••• $30.00 '"8
$25.00 I:
.-Si -!II $20.00 I~=I $15.0-0
$10.00
$5.0-0
$0.00
5 bstati 0 Costs Forecast 2010 - 2019
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
.AEP/PSO
• EMPIRE
.GRDA
KAMO
.OG&E
.OMlP'A
.WfEC
Substations transform the voltage from higher level transmission voltages to lower level distribution voltages, which is
necessary to lower the voltage of electricity to provide safe and effective power for homes and businesses. Statewide
proposed and existing substations ranged from 69kv to 161kv. Individual investment estimates and proposed service
dates vary considerably; however, over the next 10 years Providers plan to invest approximately $370M in new substations
and upgrades to existing substations.
49
Peak Capacity Forecast
Table 4-2
Statewide Peak Capacity By Resource Type for Years 2010 Thru 2019 for the Providers (megawatts)
A B C D E F H G H
Purchased
Provider Year Coal Uatural Gas Oil Hydro Renewables Power Total Capacity
(MWI IMW) lMW} IMW) (MW) IMW) (MW)
Total 2010 6,.329: 10,75B 38 888 29 1,273 19,314
Total 2011 6,438 10,936 38 888 29 1,023 19,351
Total 2012 6,455 10,937 3B 892 44 1,438 19,803
Total 2013 6,502 10,916 38 892 44 1,491 19,882
Total 2014 6,451: 10.916 38 896 44 1.537 19,882
Total 2015 6,500 10,970 38 896 44 1,448 19,896
Total 2016 6,490 10,969 38 896 44 1,456 19,893
Total 2017 6,481 11,234 38 896 44 1,513 20,206
Total 201'8 6,388 11.447 38 896 44 1,522 20,334
Total 2019 6,382 11,446 38 896 44 1,531 20,337
The statewide peak capacity by resource type for years 2010 through 2019 shows
the Providers' collective forecast in Oklahoma and reflects a gradual increase year by year
through 2019.
50
Forecast Analysis
Staffs Comparison of Forecasting Projections Against Actuals
11th ESPR 10th ESPR 9th ESPR
(Actuals from (Forecast from (Forecast from
Table 3-3) Table 4-1)1 Variance % Table 4-1)2 Variance%
2008
Adjusted Peak Demand (MW) 16,125 14,038 14.87% 14,000 15.18%
Reserve Margin With Purchases 14.46% 14.30% 1.12% 1.2.98% 11.40%
System Capabiltiy (MW) 18,457 14,256 29.47% 14,076 31.12%
Peak Power Purchases (MW) 2,386 2,124 12.34% 2,014 18.47%
2009
Adjusted Peak Demand (MW) 16,223 14,416 12.53% 14,208 14..18%
ReseNe Margin With Purchases 18.16% 15.31% 18.62% 12.04% 50.83%
System CapabHtiy (MW) 19,169 15,158 26.46% 14,076 36.18%
Peak Power Purchases (MW) 1,977 1,854 6.06% 2,078 -4.86%
1 Forecast data came from the Tenth Electric System Planning Report covering years 2005 through 2007.
2 Forecast data came from the Ninth Electric System Planning Report covering years 2003 and 2004.
Oklahoma's forecasted data from the Ninth and Tenth ESPR Reports were
compared with the current ESPR report. The adjusted peak demand for 2008 and 2009
were higher than previously forecasted for either of the two previous reports. System
capability was, in all cases, higher than previously forecasted.
51
Provider Forecasting Methods
This section describes the methods used by the Providers for developing their
forecasts.
OG&E
General Methodology
OG&E employs Quantec, an economic consulting company, to produce the long-term
energy and peak demand forecast. Quantec uses an econometric approach with five
years of historical OG&E hourly loads to estimate the utility's peak demand model. OG&E
purchases an economic forecast for the states of Oklahoma and Arkansas that Quantec
uses to drive the OG&E hourly peak demand forecast.
Quantec produces a 10-year hourly peak demand forecast for the OG&E system.
The approach taken by Quantec uses a single equation with separate intercept and slopes
for each hour of the day by day type (weekday and weekend). The model includes the
following explanatory variables:
• Hourly intercepts
• Hourly temperature terms
• Hourly temperature terms interacted with model variables
representing additional August cooling load, beginning in 1999, associated
with earlier school district starting dates
• Economic growth as approximated by real personal income
• Hourly heat buildup terms capturing the effects of weather patterns
that extend over several days (e.g., heat waves)
• The square of hourly heat buildup terms
In constructing peak demand forecast, Quantec used the last 27 years of weather
data to develop a probabilistic forecast of peak demands. This approach helps the
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company to assess the risk associated with different weather events that the company
might encounter.
AEP/PSO
KWh Forecast Process
Regression models with time series error terms were used to forecast kWh sales up
to 18 months ahead (short-term). These models use the most recent customer count, kWh
sales, weather (as measured in degree days), and other variable indicators where needed.
Weather variables are calculated from data obtained from the National Oceanic and
Atmospheric Administration (NOAA). Models for each revenue class (residential,
commercial, industrial, other retail, wholesale) and for some specific large customers are
estimated and evaluated.
Statistically Adjusted End-use (SAE) models are used for forecasting long-term
residential and commercial kWh sales. SAE models are econometric models with features
of end-use models included to specifically account for energy efficiency impacts, such as
those included in the federal Energy Policy Act of 2005 (EPACT 2005). SAE models
include the construction of structured end-use variables that embody end-use trends,
including equipment saturation levels and efficiency. Factors are also included to account
for changes in energy prices, household size, home size, income, and weather conditions.
Moody's Economy.com forecasts of these regional variables are used as drivers.
Regression is used to estimate the relationship between observed customer usage and the
structured end-use variables. The result is a model that has implicit end-use structure, but
is econometric in its model fitting technique.
Quarterly econometric models are used for forecasting long-term industrial, other
retail, and wholesale kWh sales, The process uses an economic forecast provided by
Moody's Economy.com for the United States as a whole, each state, and regions within
each state, where appropriate. These forecasts include projections of employment,
population, industrial production, and other demographic and financial variables. The long-term
forecasting process incorporates these economic projections and other inputs to
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produce a forecast of quarterly kWh sales. Other inputs include regional and national
economic and demographic conditions, energy prices, weather, and customer-specific
information.
The results of the short-term and long-term models gradually combined 12 to 18
months into the forecast horizon. During the initial stages of forecast development, the
short-term and long-term values are weighted and combined. Ultimately, the short-term
weights decrease and the long-term weights increase until the short-term weight is zero
and the long-term weight is one. At this point, the forecast results are purely from the long-term
process.
The separate steps take advantage of the relative strengths of each method. The
regression models used in the shorter-term modeling employ the latest available sales and
weather information to represent the variation in sales on a monthly basis for short-term
applications. While these models produce accurate forecasts in the short run, without
specific ties to economic factors, they are less capable of capturing the structural trends in
the electricity consumption that are important for longer-term planning. The long-term
modeling process, with its explicit ties to economic and demographic factors, is appropriate
for longer-term decisions and the establishment of the most likely or base load and demand
outcome over the forecast period.
Hourly Load, Peak Demand, and Losses Forecast Process
To forecast peak MW, historical load and temperature data is used to develop
hourly load representations (load shapes) for specific temperature increments. This data is
also used to develop daily energy models using regression techniques. These regression
model results are applied to a forecast of typical weather to generate a daily energy
forecast. This forecast is benchmarked to the aggregation of the class sales forecast plus
losses, and the load shapes are applied to the daily energy forecast to produce an hourly
load and peak MW forecast. The peak MW forecast is also bench marked to the historical
load factor relationship between peak demand and energy load using weather normalized
values.
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GRDA
The GRDA forecast was produced from a "bottom-up" approach, with the results
summed to produce a forecast of GRDA's total energy sales and system peak demands.
The process used to develop individual forecasts included econometric techniques.
In cases where valid regression equations could not be determined, judgmental analysis
was applied to forecast energy sales. The average historical loss factor was applied to the
vector of forecasted future sales to forecast the future energy requirements of the GRDA
customer. For retail customers directly served by GRDA and for municipal customers
whose sales were unknown, system energy requirements were forecasted using
judgmental analysis.
Historical energy requirements were compared to annualized 30-minute non-coincident
peak (NCP) demands to compute load factors for each customer. Historical
average load factors were then applied to the forecasted vectors of energy requirements to
project the future NCP demands of GRDA's various loads, with judgmental adjustments
made as needed to account for the addition of expected loads on the system.
Historical coincidence factors were applied to each customer's forecasted vector of
NCP demands to forecast the future contribution of the customer to GRDA's system peak.
OMPA
General Methodology
OMPA uses a city-by-city forecast generated by a multiple linear regression model
with the Consumer Price Index as the primary driver. The individual forecasts are summed
and then corrected to a forecast of OMPA as a whole. The forecast is also a weather-normalized
multiple linear regression model.
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WFEC
General Methodology
For WFEC's generation, transmission and financial planning, each member load
forecast is developed independently using econometric method. These forecasts added
together determine integrated forecast of WFEC.
Econometric equations are developed to determine the expected annual usage of
kWh for the different classes of consumers for each member distribution cooperative.
Trending, averages, and judgment have also been used for mark-ups, losses, miles of
lines, load factor, and diversity if required to develop summer and winter MW demands.
The following economic, demographic, and weather factors affecting the load
requirements are considered in economic model development:
County Population
County Per-capita Income
County Farm Employment
County Non-farm Employment
Area Heating Degree Days
Area Cooling Degree Days
Area Evaporation
Area Precipitation
Price of Electricity
Price of LP Gas
Price of Oil
Electric Heat Saturation
Air-conditioning Saturation
Household Size
County level data were converted to service area data using appropriate weights to
represent county participation. The historical data were obtained from Regional Economic
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Information System, U.S. Bureau of Economic Analysis (BEA) and projected data from
National Planning Associate (NPA). Weather data were obtained from the weather station
representing the co-operative from the National Climatological Survey monthly publications.
Historical oil and LP gas prices were obtained from Petroleum Marketing Monthly and
Natural Gas Monthly published by the U.S. Department of Energy's Energy Information
Administration and projected data from Data Resources Inc. (DRI). Saturation and
household size data were obtained from co-operative consumer surveys conducted from
time to time. Price of electricity and various markups and other information were obtained
from U.S. Rural Utility Services (RUS) Form 7.
Empire District
General Methodology
Empire uses least squares regression analysis to forecast demand and energy by
month using 12 years of historical data.
1. Regression Analysis (least squares) used to forecast energy (NSI)
Net System Input (energy) is forecast with linear regression. The independent
variables are customer count and weather. Weather is expressed as heating-degree
days (HOD) or cooling-degree days (COD) with a base of 65 degrees. Total degree-days
are used in an annual regression. In a monthly regression, HODs are used in
the winter months, COOs are used in the summer months, and the spring and fall
months may use a combination of HODs and COOs or only one depending on which
provides the best correlation to actual usage. The initial regression equations are
developed with about 1D to 12 years of history. To project future usage, the
regression equation is used with projections of future customer counts, and "normal"
weather. Normal weather is based on a 3D-year average.
y = a + bX1 + CX2
a = intercept
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b = customer number
c = HOD / COD (base 65)
X1,X2= variable coefficients
2. Regression Analysis (least squares) used to forecast peak demand
The monthly and annual peaks are forecast with linear regression. The
independent variables for the winter months (January-May, October-December) are
customer count and temperature at the peak hour. The independent variables for
the summer months (June-September) are customer count and three-day weighted
average temperatures (70% day of peak, 20% one day prior, and 10% two days
prior). To project future usage the equation is used with projections of future
customer counts and either average temperature at the peak hour or average three-day
weighted average temperatures at the peak day, depending on the month.
y = a + bX1+ CX2
a = intercept
b = customer number
c= 3DWTHI
X1,X2= variables coefficients
3DWTHI = 0.7(THI Day of Peak) + 0.2(THI Day of Peak -1) + 0.1 (THI Day of
Peak -2)
Note that the Three Day Weighted Temperature Humidity Index (3DWTHI) is only
used in the summer months (June - September). The temperature at time of peak is used
for the rest of the year.
KAMO
General Methodology
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Loads are projected using a linear regression model that uses weather normalized
historical information back to 1987. The resource forecast is determined by using a
chronological model that calculates the operational cost of various asset combinations that
meet those load requirements. Fuel projections, operations and management projections,
and capital cost are all used in this assessment. Fixed costs are gathered from industry
sources and the Energy Information Administration. The set of assets that reliably serves
the load requirements at the least cost is recommended to the Board of Directors.
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Conclusion
In this report the Commission's Public Utility Division Staff has made every effort to
present factual information concerning the state's most significant electricity Providers.
There are other electric providers in the state which are not specifically listed in this report;
however, generally the energy they produce is capatured in the purchased power of the
seven Providers who are the primary focus of this report. Although certain projections are
made over the next 10 year period, the information in this report relates primarily to the
electricity Providers who most directly impact the citizens of the state, their generation
systems, their physical capacities to meet energy demands, and the costs of providing such
electric generation.
Renewable energy resources did not show any appreciable changes since the last
Electric System Planning Report was published. Staff's projects that the next report, 2012,
should indicate significant changes in renewable energy generation. Much of the
renewable generation we have in 2010 was under development during the years covered
by this report.
Table 3-2 shows the capabilities of the self-owned generation facilities of the
Providers by various types of fuel sources. Table 3-3 shows the peak demands placed on
these systems during 2008 and 2009 along with the amount of purchased power required
to meet the total system demand during peak periods. Comparing these peak demands to
facility capacities indicates the reserve margins available for each of the major Providers,
both with and without power purchases.
Over the last several years, all electricity Providers have sustained a steady growth
in the demand for their power. Furthermore, except for the purchase of the 1,200 MW
Redbud plant by OG&E, GRDA and OMPA, no Provider had any substantial increase in its
generation facilities over the study period. In several cases minor increases in the capacity
of existing facilities resulted in actual capacity margins to increase since the Commission's
last report. During the report period, electric providers continued to rely heavily on power
purchases, but margins without purchases improved over the last reporting period. By
2009 the total capacity of the providers including purchases increased by 22% over 2007
and without the Redbud facility capacity still increased by almost 15% in a two year period
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This Electric System Planning Report also includes information (depicted in graph
form) which demonstrate the planned additions and upgrades to the Providers transmission
facilities and substations. Staff recognizes these proposals and upgrades' are significance
in the planning of Oklahoma's future growing electricity use. Many existing transmission
lines will need upgrading over the next decade. New transmission lines and substations
will also be needed to serve Oklahoma's electricity needs. Many of these additions and
upgrades are driven by the significant growth in western Oklahoma's wind energy.
Glossary
BTU - British thermal unit - A traditional unit of heat energy equal to about 1.06
kilojoules It is approximately the amount of energy needed to heat one pound of
water one degree Fahrenheit. Theoretically, 3412 BTU = 1 kilowatt hour.
The unit MBTU was defined as one thousand BTU presumably from the Roman
numeral system where "M" stands for one thousand (1,000). This is easily
confused with the SI mega (M) prefix, which multiplies by a factor of one million
(1,000,000). To avoid confusion many companies and engineers use MMBTU to
represent one million BTU. Alternatively a therm is used representing 100,000 or
105 BTU, and a quad as 1OA15BTU.
Capacity - A measure of the quantity of power; the amount of electric power delivered or
required for which a generator, turbine, transformer, transmission circuit, station, or
system is rated by the manufacturer.
Capacity Margin Percentage - (capacity - load)/capacity Under SPP rules, this is 12%
Demand - The amount of power required to meet the customer's load at a given instant or
averaged over any designated interval of time, expressed in kilowatts or megawatts.
Distribution - The delivery of electricity to a retail customer's home or business through
distribution wires or facilities of regulated public utilities.
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Energy - The capacity for doing work. In the context of electricity rates and services, the
word "energy" refers to electrical energy. In this sense, energy is a measure of the
quantity of units of electricity used in a given time period, measured in kilowatt hours.
Federal Energy Regulatory Commission (FERC) - The U.S. government agency that
regulates the price, terms, and conditions of transmission services and wholesale
sales of electricity. For example, FERC sets and enforces the wholesale electric rates
that investor-owned utility generators charge their wholesale customers. FERC also
licenses hydroelectric projects.
Generation - The process of producing electricity by converting other forms of energy into
electricity. Gigawatt (gW) - One gigawatt equals one billion (1,000,000,000) watts, or
one million (1,000,000) kilowatts, or one thousand (1,000) megawatts.
Gigawatt-Hours (gWh) - One gigawatt-hour equals one billion (1,000,000,000) watt-hours,
or one million (1,000,000) kilowatt-hours, or one thousand (1,000) megawatt-hours.
Independent System Operator (ISO) - A neutral party responsible for the management
and control of the electric transmission grid in a state or region.
Investor-Owned Utility (IOUs) - A stockholder-owned utility company that provides public
utility services to retail customers for a profit.
Independent Power Producer (lPP) - Any person who owns or operates, in whole or in
part, one or more independent power production facilities. IPPs are not owned by
utilities that serve retail end users.
Kilowatt (KW) - One kilowatt equals 1,000 watts.
Kilowatt-Hour (kWh) - This is the basic unit of measure for electric energy equal to one
kilowatt of power supplied to or taken from an electric circuit steadily for one hour. One
kilowatt-hour equals 1,000 watt-hours.
Megawatt (MW) - One megawatt equals one million (1,000,000) watts or One thousand
kilowatts (1,000 kW).
Megawatt-hour (MWh) - One megawatt-hour equals one million (1,000,000) watt-hours.
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Purchase Power Agreement - A contract specifying the terms of power purchased.
Firm Power - Power or power-producing capacity intended to be available at all times
during the period covered by a guaranteed commitment to deliver, even under
adverse conditions. On option is a take or pay agreement where the purchaser must
pay even if he does not take the delivery of power. Another option is a reserve power
agreement, where the purchaser pays the capacity charge but not the energy charge
unless he actually takes delivery.
Non-Firm Power - Power or power-producing capacity supplied or available under a
commitment having limited or no assured availability.
Reserve Power - Power which is immediately available (like a reserve generator).
Spot Power - A single shipment of Purchased power scheduled in advance for delivery
within a year
Capacity Charge - An element in a two-part pricing method used in capacity transactions
(energy charge is the other element). The capacity charge, sometimes called Demand
Charge, is assessed on the amount of capacity being purchased, while the energy
charge is assessed on the energy actually delivered.
Regional Transmission Organization (RTO) - An organization that is independent from
all generation and power marketing interests and has exclusive responsibility for
electric transmission grid operations, short-term electric reliability and transmission
services within a multi-state region. To achieve those objectives, the RTO manages
transmission facilities owned by different companies and encompassing one, large,
contiguous geographic area.
Reserve Margin - The difference between net system capability and system maximum
load requirements (peak load or peak demand).
Reserve Margin Percentage - (capacity- load)/load Under SPP rules, this is 13.6%
SPP - Southwest Power Pool
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Substation - An assemblage of equipment for the purposes of switching and/or changing
or regulating the voltage of electricity. Service equipment, line transformer installations
or minor distribution and transmission equipment are not classified as substations.
Transmission - The bulk transport of high-voltage power, typically over longer distances,
between generating plants and distribution systems.
Watt - A unit of measure of electric power.
Wind Energy I Wind Generation - Electricity generated through wind-powered turbines.
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